J. David Smith

The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays.  The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors.  This quarter we take a closer look at the Marcellus and Utica shales.Production and Activity LevelsEstimated Appalachian production (on a barrels of oil equivalent, or “boe” basis) decreased approximately 1% year-over-year through late December.  Production in the Eagle Ford, Permian, and Bakken increased 16%, 11%, and 5% year-over-year.  Despite a much-improved year-over-year commodity price environment, Appalachian production was fairly stable, largely due to high price volatility over the year, which left the markets uncertain as to where prices would be going forward. Rig counts continued to climb in all four basins over the last year.  Growth rates in the Appalachian and Permian basins were more modest, while rates for the Bakken and Eagle Ford basins were notably higher.  The Appalachian rig count rose 30% from 40 to 52 rigs.  Among the oil-focused basins, the Eagle Ford led with a 71% increase from 42 to 72 rigs.  The Bakken followed with a 56% increase (27 to 42 rigs), while the Permian had the lowest increase with a 24% increase (283 to 350 rigs). As is typical, Appalachian production has been relatively flat despite its rig count growth.  That’s due to the basin’s higher production declines which necessitate a higher rig count to maintain production levels. Commodity Price VolatilityHenry Hub natural gas front-month futures prices have experienced significant volatility over the latest year.  Prices began 2022 on a general upswing before rising sharply as the market reacted to Russia’s invasion of Ukraine in late February.  As Russia subsequently began leveraging its natural gas supplies against Europe in retaliation of Europe’s response to the war in Ukraine, natural gas prices became notably more volatile.  They rose from an early March low of $4.56 to an early June high of $9.29 — only to drop back to $5.39 in late June and then hit a 2022 high of $9.42 in late August.  By mid-December, Henry Hub had declined, albeit with only lightly reduced volatility, to $5.79.Oil prices, as benchmarked by West Texas Intermediate (WTI) and Brent Crude (Brent), also began 2022 on a steady upward trend that took the WTI from $76/bbl to $88/bbl and the Brent from $79/bbl to $91/bbl, prior to the Russian invasion.  As the reality of the Russian-Ukraine war took hold, the oil benchmarks showed a marked uptick in volatility that lasted into mid-May, with prices hitting highs of $120/bbl and $128/bbl, and lows of $93/bbl and $96/bbl.  Since then, WTI and Brent prices have trended downward, exhibiting more typical volatility other than modest rallies in August and October.  As of mid-December, WTI sat at $73/bbl and Brent at $78/bbl.Financial PerformanceThe Appalachian public comp group saw markedly strong stock price performance over the past year (through December 12th), led by Antero and EQT with price increases of 90% and 77% as of December 12th.  The remaining members of the comp group showed more modest 1-year price increases of 12% to 38%.  Prices peaked in early June for all members, except EQT, with year-to-date increases of 71% to 171%.  EQT’s stock price peaked in mid-September at a year-to-date increase of 143%.  Stock prices fell sharply beginning in mid-September but reversed direction immediately following the sabotage of the Nord Stream pipelines in the Baltic Sea that transport Russian natural gas to northern Europe.Antero and  EQT led the way among this group for several reasons.  For Antero, one reason appears to have been its lack of hedging for 2023, which has allowed it greater exposure to the uptick in gas prices and has allowed Antero to be aggressive in paying down debt.  EQT, on the other hand, does have more near-term hedging ceilings to deal with.  However, its strength is in its operational efficiencies, whereby their recent literature demonstrates breakeven operating expenses at $1.37 per mcf.  This is among the lowest in the industry and allows them to accumulate cash flow.ConclusionAppalachian production held steady in 2022 despite historically high commodity price volatility driven by the Russian-Ukraine war, the sabotage of the Nord Stream pipelines, and rising LNG exports to Europe to stave-off potential winter heating shortages.  The Q4 Appalachian rig count is at a level beyond that needed for production volume maintenance, so there would seem to be at least some potential for Henry Hub price reductions going into 2023.  However, the demand for new natural gas supplies to Europe provides a countervailing wind to any potential downward movement in natural gas prices.  In the end, the natural gas markets seem to be in the midst of a series of events that promise continued supply and demand shifts with no certainty as to where the market will go in 2023.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.

The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. This quarter we take a closer look at the Bakken.Production and Activity LevelsEstimated Bakken production (on a barrels of oil equivalent, or “boe” basis) increased by 5% year-over-year in September. Bakken production, relative to the September 2021 level, plunged nearly 20% in April due to the impact of back-to-back blizzards but had recovered to the September 2021 level by June 2022. Production in the Eagle Ford and Permian were 13% and 8% higher, respectively than in September 2021, without the short-lived plunge seen in the Bakken. The gas-focused Appalachia region production relative to September 2021 levels was more stable than the oil-focused regions, with relative production only varying within a band of -1% to 4%, ending at a year-over-year 3% increase in September 2022. As of September 16, 2022, 40 rigs were operating in the Bakken, marking a 74% increase from September 10, 2021. Eagle Ford, Permian, and Appalachia rig counts were significantly higher than year-earlier levels at 112%, 35%, and 24% increases, respectively. The Permian continued to command the largest number of rigs at 343, with the Eagle Ford and Appalachia closer in-line with the Bakken at 72 and 47 rigs, respectively. Oil Climbs While Gas Shows Heightened VolatilityOil prices, as benchmarked by West Texas Intermediate (WTI) and the Brent Crude (Brent), rose from $72/bbl and $75/bbl, respectively, in September 2021 to $85/bbl and $90/bbl, respectively, as of September 16, 2022. While the rise in pricing was fairly steady through mid-February 2022, the Russian invasion of Ukraine spurred a series of ups and downs, with prices spiking to a high of $120/bbl (WTI) and $128/bbl (Brent) in early March, immediately followed by a plunge to $94/bbl and $96/bbl in mid-March. Subsequent spikes and dips were somewhat more muted, but prices remained volatile through early June. A general price decline during the third quarter resulted in prices at the $85/bbl and $90/bbl level.Henry Hub natural gas front-month futures prices dipped from a late 2021 high of $5.48/mmbtu to a low of $3.44/mmbtu near 2021 year-end as commodity markets incorporated indications of rising production levels and ebbing weather-driven demand. Pricing subsequently rose to as high as $9.29/mmbtu in June on weather-driven demand and lacking supplies due to a reduction in Russian exports. In mid-June Henry Hub pricing began a sharp decline on the announcement that prices recovered over the remaining two months of the September LTM period, albeit with some volatility, to end at $7.81/mmbtu.Financial PerformanceThe Bakken public comp group's latest twelve-month financial performance (stock price) analysis was reduced to two subject companies and the XOP SPDR, as a result of the Whiting and Oasis merger in March 2022. The combined Whiting/Oasis company, Chord Energy, appears in our analysis as CHRD.The Bakken comp group showed strong price performance from year-end 2021 through early June, with increases ranging from 63% to 83%, largely reflective of oil prices. The subsequent decline in commodity prices, which ran nearly un-checked for two months, slashed the analysis period performance to increases of only 3% and 46%, with Chord posting a decline that nearly wiped out its post September 2021 gains. Prices have recovered since July with one-year gains of 42% (Chord) to 61% (Continental).ConclusionThe Bakken showed a general increase in activity over the last year, albeit with a large winter storm disruption and subsequent production recovery along the way. Rig counts have risen on strong commodity pricing, despite the oil price decline in Q3 2022. Share prices generally increased early in the latest twelve-month period, with a sharp decline in Q3 tied to oil prices slipping. Share prices recovered enough in late Q3 to show reasonably strong year-over-year growth as of September.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America and around the world. Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.

The Oilfield Services (“OFS”) industry has long been known for its cyclicality, sharp changes in “direction” and demand-driven technological innovation.  One segment of the OFS industry that is among those most subject to recent, rapid change is the Oilfield Water segment – including water supply, use, production, infrastructure, recycling and disposal.  In this week’s Energy Valuation Insights blog, we look to key areas of the Oilfield Water segment – oilfield water disposal and oilfield water recycling – and address both recent trends and where the segment is going in the near-future.Oilfield Water DisposalThe oilfield water disposal (saltwater disposal) industry remains dynamic with numerous forces driving change.  Key among those forces are volume demand, growth in water recycling and rising seismic activity in key shale basins.  With the rebound in oil prices since 2020, demand for oilfield water disposal has rebounded as well. While oilfield water recycling continues to grow rapidly in volume, there remains a very significant imbalance between produced water and recycling volumes.  The portion of produced water that is being recycled was estimated at 20%, per Dr. Chris Harich, Chief Operating Officer at XRI during his presentation at the recent Oilfield Water Markets Conference (“OWMC”).Additional recent factors impacting the saltwater disposal (“SWD”) industry, particularly in prominent U.S. shale plays in Oklahoma, Texas and New Mexico, is the distinct increase in seismic events that are attributed to oilfield production and waste disposal activity.  In September 2021, the Texas Railroad Commission initiated added reporting, permitted volume reductions and even cessation of operations of certain SWDs near high seismic activity areas, referred to as seismic response areas (“SRA”).  As a result of the rising demand for oilfield water disposal capacity and reduced disposal availability in certain areas, Kelly Bennett, CEO & Co-Founder of B3 Insight, expects (i) disposal capacity to remain far below produced water volume through 2026, (ii) increased demand for additional SWD facilities and a race for development of shallow SWDs, (iii) more produced water being transported outside of production areas for disposal, and (iv) a resulting rise in water management costs to producers.In regard to the use of shallow SWD wells, one OWMC panel (including Gauri Potdar, SVP Strategy Analytics at H2O Midstream; Laura Capper, President of Energy Makers Advisory; Max Harris, Director at EIV Capital; and Ken Nelson, President & Co-Founder of Blue Delta Energy) noted that shallow depth SWD activity can interfere with production activity in the immediate area, inherently leading area producers to push back against shallow SWD development projects.Finally, how to finance projects providing additional oilfield water disposal capacity comes with challenges not faced in many other industries.  Bennett noted that as a dynamic industry that seems to be becoming even more dynamic, financing considerations are becoming even more complicated in recent years.Oilfield Water RecyclingOn the recycling side of oilfield water management, the complications aren’t any easier to deal with.  While demand for oilfield water recycling is certainly on the rise, the headwinds to providing recycling services are many and naturally push upward on the cost of recycling services.  However, as with most challenges in the oilfield services industry, new technology and innovation are expected to drive industry participants to overcome the inherent barriers.Notable among the oilfield water recycling headwinds are cost, lack of detailed information as to needed recycling volumes, the need for disposal of certain by-products of recycling, and landowners that are economically predisposed against recycling.  The cost of recycling services likely needs no explanation; however, the logic as to the other headwinds may not be quite as obvious.The OWMC’s panel on the Mechanics of Recycling at Scale (including Jason Jennaro, CEO of Breakwater Energy Partners; Dr. Chris Harich; David Skodak, SVP Water Treatment at CarboNet; Ryan Hassler, Senior Analyst with Rystad Energy; and Joseph De Almeida, Director Water Strategy & Technology at Occidental Oil and Gas), noted that currently there are no oilfield water recycling reporting requirements.  As such, potential recycling project developers have to deal with somewhat rough estimates as to demand volume, rather than a more concrete indication as to the recycled water volume potential in a particular production area.  As with any potential investment, less specificity as to the potential market for services is “read” as greater risk, thereby providing greater uncertainty to project investment.As to byproducts of oilfield water recycling, one only has to go as far as the industry name for the liquid being recycled – saltwater.  Yes, by volume, salt is logically one of the primary byproducts of saltwater recycling.  In the Permian Basin, already known for its high produced water to oil cuts, salt content is higher than found in other basins resulting in higher recycling costs due to the sheer volume of salt byproduct and driving up the cost of capital for development.The last headwind referenced is the economic motivation of landowners in the production area.  The OWMC’s panel on Engaging Landowners (including Rick McCurdy, VP-Innovation & Sustainability at Select Energy Services; Brian Bohm, Sustainability Manager with Apache Corp; Nate Alleman, HSE and Water Infrastructure Specialist at ALL Consulting; Matthias Bloennigen, Director – Consulting with Wood Mackenzie; and Jason Modglin, President of Texas Alliance of Energy Producers) noted that landowners are often compensated to supply water for oilfield exploration and/or production use, or for use of their property in the disposal of saltwater.  As such, these landowners naturally aren’t in favor of the development of water recycling projects that are viewed as cutting into the fees they are being paid under existing contracts.Recycling SolutionsDespite the abundance of recycling headwinds, expectations are that all will be successfully addressed and overcome by the innovation of industry participants.  Costs can be reduced by various means including the extraction of certain rare metals commonly found in produced water, use of flare gas as an inexpensive energy source for recycling operations, the development of recycling equipment that can be readily relocated, and greater cooperation in water management asset “sharing” between basin operators.  In addition, increased recycling reporting requirements can assist in reducing some of the risk inherent in recycling projects and landowners can be educated as to recycling being a complementary service to existing water supply and disposal operations, thereby decreasing the natural resistance to recycling projects.ConclusionAs has always been true of the OFS industry, change brings challenges – and that is no different in the Oilfield Water segment.  The dynamics of oilfield water disposal and oilfield water recycling continue to evolve, but the OFS industry has a long history of addressing and conquering its challenges, and there’s no reason to doubt the current challenges will also be conquered.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers, and Big 4 Auditors. These energy-related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.

In our Energy Valuation Insights post from last week, Bryce Erickson focused on Oilfield Services (OFS) company valuations.  This week we follow the same OFS theme, but with a focus on OFS “expectations” and the question: “Has the OFS industry turned the corner to a more prosperous outlook?”Enthusiasm Among ExpertsOne can’t come away from a review of current OFS industry musings without feeling that, in the endless battle between OFS Bulls and OFS Bears, the Bulls have gained the advantage and are on the rise.From Bloomberg Intelligence – and under the noteworthy heading of OFS Recovery to Reach Cruising Altitude in 2022 – we find that oilfield services industry revenues are expected to grow by ten to fifteen percent in 2022, compared to nearly flat revenue growth in 2021.  North American OFS is expected to lead the way with likely 20% revenue gains.Representatives of investment banking firm Evercore’s E&P and OFS groups noted in a recent Natural Gas Intelligence piece that the E&P and OFS groups’ expectations for 2022 remain bullish as they believe we are in the early stages of a long, strong, multi-year E&P spending upcycle.In its recent industry outlook, Zacks noted that the OFS industry is bright again and that the business environment for E&P activities has shown drastic improvement.  That improvement is reflective of oil prices having returned to the “glorious days,” thereby leading drillers to return to the oil patch, resulting in significantly improved demand for oilfield services.Many more significantly optimistic references are available, but suffice it to say that expectations for the OFS industry (due to E&P industry activity) have changed a lot, for the better, in the last year.Basis for OptimismSo, what are the industry experts seeing that is leading to this optimism?  In short:oil demand rising as the Covid pandemic recedes and the world begins the return to normal levels of activities that require energy use,significant potential for an oil supply shortage, andrecent under-investment in the new production needed to sustain supply. In light of the factors above, industry analysts are detailing some very positive expectations for the OFS industry.  Such as: The Energy Information Administration (EIA) forecasts that global consumption of petroleum and liquid fuels will average 100.6 million b/d for all of 2022, which is up 3.5 million b/d from 2021 and more than the 2019 average of 100.3 million b/d. On top of which the EIA forecasts that global consumption of petroleum and liquid fuels will increase by 1.9 million b/d in 2023.  So, for the first time since Covid reared its head in early 2020, global oil consumption is expected to rise to a level materially higher than pre-Covid consumption. Mizuho Securities USA LLC indicates in a January 2022 NGI article (U.S. E&Ps, OFS Players Expected to Reset in 2022, with Eyes on Inflation, Supply Chains) that in order to generate sustainable oil volumes through 2022 based on current production volumes, the rig count across the five major U.S. oil basins would have to increase by 100 rigs, compared to a 178 rig increase since January 2021. Mizuho further indicated that the rate of completions in the major U.S. basins is probably sufficient to support growth.  However, the drilled but uncompleted (DUC) inventory is at a historically low level, so more drilling activity will be required.  Otherwise, the needed 2022 growth in the U.S. supply could be materially held-back. Early Indications Favoring the BullsAs to early evidence supporting those expectations, Baker Hughes’ most recent North American rig count is at 854, a level not seen since the onset of the Covid pandemic in March 2020.According to Bank of America, due to the draw-down in global oil inventories in 2021, the oil market is anticipated to move from a steep deficit to a more balanced market.  With that in mind, BofA is predicting that WTI and Brent will average $82 and $85 over the course of this year.Other industry analysts, including Goldman Sachs Group, are indicating that oil prices could reach $100 during 2022, while forecasting average 2022 oil prices at $85. Employment in the U.S. oilfield services and equipment sector rose by an estimated 7,450 jobs in December, according to the Houston-based Energy Workforce & Technology Council. Zacks Equity Research summarized how all this ties in to the OFS outlook: “The price of West Texas Intermediate (WTI) crude is trading higher than $89 per barrel, marking a massive improvement of more than 50% in the past year. Strong fuel demand across the world and ongoing tensions in Eastern Europe are aiding the rally in oil prices. The massive improvement in oil price is aiding exploration, production and drilling activities. This, in turn, will boost demand for oilfield service since oilfield service players assist drillers in efficiently setting up oil wells.” Potential HeadwindsOf course, there are also headwinds for the OFS sector that will have to be dealt with, including inflation being a key consideration.  As detailed in our January 14, 2022 Energy Valuation Insights post, industry analysts are projecting over 30% average OFS revenue growth in 2022, although average EBITDA margins are expected to edge downward from 13% toward 12%.  Inflationary factors are pushing up OFS costs, but such increased costs are expected to only partly be passed through to their E&P clients.In addition, the Biden Administration is clearly adamant about getting the country moving rapidly away from hydrocarbon-based energy, despite the public already complaining mightily about fast-rising energy prices and more general inflationary pressures.  Where those political winds will carry the matter is anyone’s guess.In SummaryAs indicated, the companies that comprise the OFS segment – at least those that survived 2020 – experienced some stabilization in 2021, and are now facing what appears to be a market that has the industry analysts feeling fairly bullish.  Influenced by rising oil demand, an existing shortage, and recent E&P investment well below the sustainable level, expectations have moved from OFS stabilization to strong multi-year OFS growth in 2022 and likely beyond.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers, and Big 4 Auditors. These energy-related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.

In our prior Energy Valuation Insights post – What a Difference a Year Makes –  Mercer Capital’s Bryce Erickson dug into the key aspects of the energy industry during 2021, including oil and gas pricing, stock price performance, rig counts, production levels, capital spending, and LNG facility development.  It’s well worth a read!In today’s post, we continue the “what a difference a year makes” theme, but now with a focus on analyst projections, then-and-now (then being as of year-end 2020, and now being as of year-end 2021) and energy stock valuation multiples.For the purpose of our analysis, we utilized the Capital IQ system and identified publicly traded energy companies, trading on the NYSE and NASDAQ exchanges, and operating in three broad areas – exploration and production (E&P), oilfield services (OFS), and midstream.The resulting pool included 44 E&P, 32 OFS, and 29 midstream companies1,227 forward (i.e., for the next year) revenue estimates were included in the analysis – 666 as of year-end 2020, and 561 as of year-end 20211,735 forward EBITDA (earnings before interest, taxes depreciation and amortization) estimates were included in the analysis – 854 as of year-end 2020, and 881 as of year-end 2021Potential survivor bias was eliminated by including the same set of companies as of both year-end 2020 and 2021So, What Are the Analysts Expecting?Exploration & ProductionWe’ll start at the drill bit end of the industry – the E&P companies.  Revenue growth expectations (233 and 201 analyst estimates as of year-end 2020 and 2021, respectively) actually didn’t change significantly.  As of year-end 2020 the median estimated 1-year revenue growth was 25.8%, with only a small increase to 29.7% as of year-end 2021.  An improvement certainly, but by no means earth-shaking.  A bit more significant for the E&Ps was a 7.5 percentage point increase in the median estimated EBITDA margin, from 57.7% to 65.2%.  The real “move” in E&P estimates came from the combination of slightly improved revenue growth estimates and EBITDA margin estimates, buoyed by the rise in commodity prices.  Those two estimates “teamed-up” for a mere 17.0% median EBITDA growth estimate at year-end 2020, but a very significant 119.8% median EBITDA growth estimate at year-end 2021.Oilfield ServicesNext up we look to the service and machinery providers to the E&Ps – where we find a much more positive outlook today relative to a year ago.  Last year’s median revenue growth estimates sat in negative territory at -6.3%.  Sentiment was much improved at year-end 2021 with a median revenue growth estimate at 23.9%.  However, OFS EBITDA margins paint a different picture.  Despite the expectation for strong revenue growth, EBITDA margins are expected to actually decline slightly from a year-end 2020 median forecast of 12.8%,d to a current figure of 12.2%.  This implies that while demand and utilization will be strong, pricing power for oilfield service companies will slip somewhat.  The combination of revenue growth and EBITDA margin estimates, though, show a strong improvement in EBITDA growth expectations, from a median expected decline of 5.3% at year-end 2020 to a median expected growth of 34.0% at year-end 2021.  This is not as strong as EBITDA growth expectations among the E&Ps, but a very welcome increase all the same. MidstreamMidstream operators of course are the “Steady Eddies” of the energy industry – that in large part is due to the very nature of the services provided and the more contractual/commitment orientation of the midstream business.  As one would expect, the difference between 2020 and 2021 median analyst estimates are much less material for midstream companies.  Median revenue growth estimates were quite low at only 1.0% at year-end 2020, but improved to a median growth estimate of 7.5% as of year-end 2021.  EBITDA margin estimates actually declined a bit more than those for OFS companies, with a 3.3 percentage point dip from 42.5% at December 2020 to a 39.2% median at December 2021.  In combination, the revenue growth and EBITDA margin estimates result in the median EBITDA growth estimate of 2.1% in December 2020 and a median estimated growth of 9.0% as of December 2021. Valuation MultiplesLastly, in our comparison of year-end 2020 and year-end 2021 within the energy industry we look to valuation multiples across the three energy sectors.  Here we see how the combination of uncertainty of future operating results (risk) and growth expectations combine in the form of enterprise value multiples of EBITDA, on both a trailing (latest twelve months – LTM) and 1-year forward EBITDA basis.  Starting with the midstream companies, we see that modest improvement in revenue expectations and slight reduction in EBITDA margins combine with risk perceptions for fairly modest changes from 2020 to 2021 LTM and forward valuation multiples.  LTM midstream multiples edged up from 9.0x to 10.0x, while the Forward multiples showed an even more modest increase from 8.7x to 9.0x.The negative 2020 EBITDA growth expectations and much larger (than Midstream) 2021 EBITDA growth expectations result in a very different combination of 2020 to 2021 and LTM to forward OFS multiples.  Here we see the median LTM multiple jumping 34% from 2020 to 2021, while the forward multiple decreased by 24%.  That with 2020 forward multiples 32% greater than 2020 LTM multiples, and 2021 forward multiples 50% below 2021 LTM multiples.By far the largest swing in 2020 to 2021 and LTM to forward multiples comes from the E&P companies.  With only modest EBITDA growth expectations as of 2020, the E&P LTM and forward multiples are quite similar at 5.8x and 5.2x, respectively.  However, the 119.8% median estimated EBITDA growth at year-end 2021 results in a much larger LTM to forward differential of 6.7x – 9.7x LTM compared to 3.7x forward.  That high level of EBITDA growth expectations in 2021, compared to the much more modest growth expectation as of 2020 results in a 3.1x differential between 2020 LTM multiples and 2021 LTM multiples (5.8x versus 9.7x).  As with OFS forward multiples, the E&P forward multiples decreased markedly from 2020 to 2021, from 5.2x to 3.7x. In SummaryThe energy industry that was hammered in 2020 by the combined OPEC+ induced oil glut and COVID related oil demand decline showed a mixed bag of marginal and tepid operating result growth expectations at year-end 2020, but is showing much greater expectations as analysts look ahead into 2022.  However, it is the energy industry – so, be ready for the next cycle shift.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers, and Big 4 Auditors. These energy-related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.

There’s been much coverage of the run-up in oil prices since November 2020, from $37/barrel (WTI) to current prices in excess of $80/barrel.  That of course ignores the April to October 2020 $28/barrel recovery from the Covid/OPEC+/Russia-induced oil price death plunge during the February to April 2020 period. Now it seems that it’s natural gas’s turn at the price run-up game.While Henry Hub (a benchmark for natural gas prices) also showed a post-Covid recovery from its March to June 2020 lows (near $1.60/MMbtu) to prices generally in the $2.60 to $3.00 range from October 2020 to May 2021, it has since been on a run that has taken it to recent highs over $5.70.  So, what gives?  In this week’s blog post, we address the market forces that have led to higher natural gas prices despite near record U.S. natural gas production levels.Production Is High, So Why Are Prices Rising?Per U.S. Energy Information Administration (EIA) data, 3Q2021 U.S. natural gas production neared its prior peak level, and EIA analysts expect that production will reach new record highs during 3Q2022.  With such high production, basic economic theory would suggest that natural gas prices should be facing downward pressure.  However, there’s the demand side of the equation to consider as well.  Since the 2020 Covid-induced demand decline, the increase in natural gas demand has exceeded production recovery.  Therefore, a supply versus demand imbalance has pushed prices up at an unusual rate. Why Not Just Increase Production to Satisfy Demand? A natural question to be asked is, why wouldn’t the gas producers simply increase production to meet the heightened level of demand?  That’s where an interesting set of factors come into play, with one such factor being future gas price expectations.Why wouldn’t gas producers simply increase production to meet demand? Future gas price expectations.Tsvetana Paraskova, writing for OilPrice.com, notes that producers in Appalachia, America’s largest gas-producing basin, are expecting stronger pricing signals in the future curve for gas prices a year or two from now.  As such, to some extent, those producers are looking at to (i) invest now to boost production for which they’ll receive current prices, or (ii) delay that investment to boost production until later when they’re expecting to sell the same volumes at higher prices.  Depending on their level of confidence in those higher future prices, they may be significantly incentivized to hold off on those volume boosting investments. Furthermore, Peter McNally, with the consulting firm, Third Bridge, reminds us that the more recent trend among oil and gas investors in preferring more near-term return on investment (current distributions to investors), rather than more drilling (with larger distributions down the road), has pressured the producers to ease back on their drilling programs that would otherwise help maintain production levels.Where Is Demand Coming From?A natural question to be asked is, where is all the demand side pressure coming from?  The answer, in large part, is exports.  While the U.S. has exported natural gas via pipeline for many years, the capacity for LNG exports has ballooned in recent years and reached record levels in 2020 and 2021. Two regions are driving demand for U.S. LNG exports.  The first is Europe.  After the much colder than usual winter, natural gas inventories remain well below typical seasonal levels.  As a result of the lower inventories, Europeans are paying four to five times as much for natural gas relative to what is being paid in the U.S.  That creates quite the incentive for U.S. produced natural gas to be exported, rather than staying within the country.  The second is China.  Reuters reports that China has become concerned in regard to its country-wide fuel security and is facing a winter fuel supply gap.  That, in the midst of Asian gas prices that have increased more than 400% in 2021, has led to advanced talks between top Chinese energy companies and U.S. LNG exporters for the purpose of locking-in future U.S. LNG export volumes. What Does This Mean for the U.S.?As a result of the indicated supply and demand forces at play, Reuters reports that power crunches are already hitting large economies such as China and India.  While the impact in the U.S. (so far) has been relatively modest, expectations are for U.S. consumers to spend much more to heat their homes this winter.  In the U.S., nearly half of homes use natural gas for heating purposes, as natural gas has traditionally been the most economical source for heating residences.  The U.S. Department of Energy estimates that those homeowners will pay 30% more for natural gas this winter compared to last winter.What Are the Ripple Effects of Higher Natural Gas Prices?While home heating is a more straight-forward result of the higher natural gas prices, there are numerous ripple effects that are far less obvious.  Natural gas is a key input to a number of industries where higher natural gas costs will naturally be passed through to consumers.  Bozorgmehr Sharafedin, Susanna Twidale and Roslan Khasawneh, with Reuters, note several such industries including steel producers, fertilizer manufacturers, and glass makers having been forced to reduce production due to the higher natural gas prices.Industrial Energy Consumers of America, a trade group representing chemical, food and materials manufacturers has even urged the U.S. Department of Energy to limit U.S. LNG exports in order to ease their member firms’ energy-related expenses.  Food producers in particular are reporting shortages of CO2 (a byproduct of fertilizer production) that is used in packaging processes, meat processing, and even for putting the “fizz” in carbonated drinks and beer.  As a result, prices for those types of products are already on the rise.ConclusionAs indicated, the market forces at work in the supply and demand for U.S.-produced natural gas are many, and come from both domestic and foreign sources.  The current supply/demand gap has pushed natural gas prices to recent record levels, with the impacts being both obvious in winter heating costs, and not so obvious in higher food and beverage prices. Keep reading this blog as we continue to track natural gas pricing and other energy-related industry topics.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers and Big 4 Auditors. These energy related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.

In the midst of the COVID pandemic, the rise of the Delta-variant, and general summer distractions, not a lot of attention has been given to the 117th Congress’ H.R. 1512 – aka the “Climate Leadership and Environmental Action for our Nation’s Future Act” or the “CLEAN Future Act.”  The Act was first presented as a draft for discussion purposes in January 2020.  After more than a year of hearings and stakeholder input, it was introduced as H.R. 1512 in March 2021.  The Act’s stated purpose is:“To build a clean and prosperous future by addressing the climate crisis, protecting the health and welfare of all Americans, and putting the Nation on the path to a net-zero greenhouse gas economy by 2050, and for other purposes.”As broad as that stated purpose is, it’s not surprising just how far-reaching the implications of the nearly one-thousand-page-long Act are for many sectors of the U.S. economy.  While Congress is a long way away from any bipartisan climate legislation being enacted, the Act provides some insight regarding the plans of the House Democrat Leadership for a clean energy future.  It also potentially serves as a “red flag” to many industry participants that will be materially impacted by those plans.Of particular interest to the Oilfield Water Management sector, is Section 625 of the Act.  In that section, the Environmental Protection Agency would be ordered to determine whether certain oil and gas production byproducts, including produced water, meet the criteria to be identified as hazardous waste.  The legislation in fact, mandates that the EPA must make its determination within a year after the Act becomes law.Per the EPA’s April 2019 study publication, Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action, produced water is defined as “the water (brine) brought up from the hydrocarbon bearing strata during the extraction of oil and gas. It can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process.”  Since 1988, EPA has held that oilfield-produced water should be regulated as non-hazardous waste.  As such, produced water has been subject to the Resource Conservation and Recovery Act’s (RCRA) much less restrictive Section D provisions regarding non-hazardous waste, instead of RCRA Section C’s much more restrictive provisions regarding hazardous waste.Per a June 2021 report by Rice University’s Baker Institute for Public Policy, if the EPA’s Act-directed review of the 1988 produced water’s non-hazardous classification is revised to a hazardous classification, an enormous disruption in oilfield water management would result.  The report specifies that severe disposal capacity constraints would be brought into play.At the current time, oilfield produced water disposal is available at an estimated 180,000 Class II disposal wells located throughout the U.S.  If the Act were to lead the EPA to reclassify produced water as hazardous waste, all produced water would have to be disposed of in Class I wells, of which there are far fewer.  The EPA’s data on Class I wells indicates that approximately 800 such wells are in existence; however, the wells are located in only 10 states due to geological requirements.  The majority of those Class I wells are located in Texas and Louisiana.  The EPA also indicates that only 17% of the Class I wells are available for hazardous waste disposal.  Adding to the limited Class I well availability matter, the University of Wisconsin Eau Claire reports that those hazardous waste  disposal wells are located at a mere 51 facilities.                                                                                                                                                                             Source: EPA                             The cost of transporting Eagle Ford and Permian Basin produced water (in excess of 10 million barrels per day), for example, hundreds for miles to Class I facilities on the Texas and Louisiana Gulf Coast would be prohibitive to many producers.  As a result, a substantial reduction in U.S. oil and gas production would be a natural and expected consequence, with the economic and industry ripple effect of such reduced production being enormous.  Gabriel Collins, the Baker Botts Fellow in Energy and Environmental Regulatory Affairs at the Baker Institute, notes that any such re-classification would very likely lead to multi-system disruptions severe enough to make achieving the Act’s climate, energy, environmental, and social objectives impossible.While the Act is awaiting action by the U.S. House of Representatives, it’s well worth Oilfield Water Management industry participants keeping a close eye on it.  Although Congress’ attention has been focused on COVID relief and is now focused on infrastructure matters, the CLEAN Future Act will eventually come to the forefront, with potentially far-reaching impacts if unchanged from its current form.ConclusionMercer Capital closely monitors the Oilfield Water Management and other areas of the Oilfield Services industry.  We’re always happy to answer your OFS-related, or more general valuation-related questions.  Please contact a Mercer Capital professional to discuss your needs in confidence.

To say that 2020 has been “rough” for U.S. oil and gas (O&G) industry participants would be the height of an understatement.  The one-two punch of the Saudi-Russia dust-up over oil market share, and the COVID-19 pandemic, which together spiked oil supplies and made demand plunge, combined to set-up for a record bad year for the O&G industry.  Oil prices, that ended 2019 near $60/barrel (WTI), tumbled below $22/barrel in late March, and hit a 2020 low of $17/barrel in April.  A much welcome partial recovery during the month of May led to a somewhat stabilized price range of $36-$43/barrel through the third quarter.  While $40/barrel oil prices provided at least some relief to O&G industry participants, prices at that level aren’t expected to lead to anything close to a recovery to pre-2020 activity levels.  The industry continues to “flow red” with continued bankruptcies piling-up. Bankruptcy courts have been busy as a result of the O&G industry downturn.  Already this year 36 bankruptcies were filed among the production segment operators alone.  Industry insider conversations have included concerns that there could be 60-70 additional producer filings by the end of the year. If those predictions come true, 2020 would represent a record year for O&G-related filings in the annals of the bankruptcy courts.   While that may seem like an unusually bad turn for a six-month period of depressed prices, it’s worth noting that the industry was significantly stressed beforehand.  Natural Gas Intelligence’s Andrew Baker noted that the anticipated cutbacks in future capital expenditures among the producers for drilling, completions, and other activities in the field will most certainly spread the bankruptcy trend to the oilfield services (OFS) segment that never completely recovered from the 2014 industry downturn.  Baker indicated that “many smaller or highly leveraged OFS companies may not be able to hold on” and will be forced to seek the protection of bankruptcy courts. As Baker referenced, size and financial leverage can generally contribute to an OFS participant business being forced into a bankruptcy filing.  In this edition of Mercer Capital’s Energy Valuation Insights blog, we explore some of the many factors that play into making it more (or less) likely that an OFS participant will survive an industry downturn intact, or succumb to market pressures and enter into bankruptcy. OFS Bankruptcy DifferentiatorsThere are most certainly many factors that may contribute to, or deter, an OFS company’s need to file for bankruptcy protection during an industry downturn.  Some are more general and more obvious, while others are more specific and not as readily discerned.  Here we address some of the more general factors (margins, financial leverage, and breadth of product/service offerings), some industry specific factors (customer sectors and basins served), and the benefit of industry experience.General FactorsAs in any industry, the ability to survive a downturn in the OFS industry is all about maintaining cash flow, and therefore liquidity.  No surprise here, a company generating higher margins in “normal” industry conditions is more readily able to navigate a downturn when the company’s margins are likely to get pinched.  As such, bankruptcies during a downturn in the industry are materially more likely among highly competitive sectors of the OFS industry where margins tend to be lower, as opposed to less competitive sectors, where margins tend to be more robust.  Beyond general competition levels, a particular OFS company’s margins may be influenced by a number of factors.  These include proprietary products or processes, its having embraced efficiency inducing technology and automation, and other factors that contribute to lower cost of sales, or operating expenses.  With higher margins, an OFS company is able to endure the margin reductions that come with industry downturns with a significantly lower probability of reaching a financial breaking point....the ability to survive a downturn in the OFS industry is all about maintaining cash flow, and therefore liquidity.Similarly, the degree to which an OFS company makes use of financial leverage to enhance returns can play into its ability to weather an industry storm.  Take Company A and Company B that both generate the same operating cash flow margins – margins before consideration of financing costs in the form of interest expenses on outstanding debt.  If Company A carries a lower level of debt financing (relative to Company B), its operating cash flow will be greater than Company B’s.  The cash flow differential may not be a make-or-break matter during normal industry conditions when both companies are generating significant cash flows relative to their interest expense.  However, during periods of reduced cash flow, the more leveraged company may reach a point where operating cash flows are inadequate to meet its interest payments.  So, the financial leverage that enhances return during the times of industry strength can be the same financial leverage that leads to distressed liquidity during industry downcycles.An OFS company’s breadth of product or service offerings can also impact the ability to maintain operations during a downturn.  Larger OFS participants, with multiple product or services offerings, have the benefit of being able to consider shifting its efforts among various offerings.  In that way, the company can emphasize operations where it can continue providing more productive (profitable) lines and deemphasize less productive lines.  It may even be in a position to sell-off assets related to less productive lines in order to maintain liquidity to continue operations of productive lines.  WorldOil Magazine’s David Wethe cites examples of this type of shifting of products/services in Schlumberger’s sale of its land-rig unit in the Middle East and Precision Drilling’s sale of its Mexican operations as the companies struggled in recent years.  Unlike these larger industry participants, smaller companies with very limited product or service offerings, don’t have nearly the same level of flexibility.  Among these smaller OFS companies, diversity of offerings may simply not exist.  That leaves the businesses without the ability to shift away from less profitable products or services, and therefore make them more prone to the necessity of a bankruptcy filing.Industry-Specific FactorsThe diversity and breadth of the OFS industry brings additional factors that may influence an industry participant being forced into a bankruptcy filing.  Despite the misnomer, the OFS industry includes providers of products and services to both oil-focused and gas-focused E&P companies.  The graphic below provides some insight as to just how wide an array of products and services are represented within the OFS industry.Sub-Sectors FocusDue to the significant differences between the operations of the OFS industry participants, an industry downturn doesn’t impact all OFS participants to the same degree.  For instance, OFS businesses that disproportionately serve the natural gas side of the industry were not as significantly impacted by the precipitous drop in oil prices during the 2020 second quarter.  In the same way, OFS participants may be impacted quite differently based on the E&P subsector that they serve.  For example, during the 2020 oil price disruption, new drilling operations were much more adversely affected than were continuing production operations.  Following a sharp decline in oil prices, exploration operations may be curtailed much more so than production operations.  For example, when oil prices are in the $35 to $40 per barrel range, it can be economically beneficial to continue production from existing wells, but quite uneconomically viable to incur the cost of drilling new wells.  Even much less economical to incur exploration related expenses.  As such, OFS companies whose products or services support production activities – fracking, well maintenance services, and production chemical providers – face less dire circumstance at $35 to $40/barrel prices than OFS companies that support exploration activities – geological, seismic, drilling, and site preparation services.Basin FocusBeyond the differences between serving the oil versus gas subsectors, and the differences between serving exploration versus production subsectors, there are differences in the basins that a particular OFS business focuses on.  These differences can generally be categorized into three areas – type of oil, midstream transportation availability, and production cost.   Different basins may produce different types (grades) of crude oil (light versus heavy, sweet versus sour, etc.), which require varying levels of refining in order to generate end products.  As such, the “price” of oil isn’t uniform across basins, and as a result, a drop in oil demand can impact different basins to varying degrees.[caption id="attachment_34074" align="alignnone" width="726"] http://www.eia.gov/maps/maps.htm[/caption] Similarly, the midstream transportation assets of a particular basin can influence the price of oil based on the location of the production facilities.  Basins, where pipeline capacity is lacking, may have a higher cost of getting the oil to refining facilities and, therefore, require higher prices to justify continued production.  In much the same way, different basins can have materially different production costs per barrel depending on the age of the fields and the specific geology of the field. As with basins that suffer from higher costs in getting produced oil to refineries, basins that have higher production costs (the total cost of bringing oil/gas to the surface) may not have the needed economics to justify continued production at oil prices that allow for continued production from basins with lower production costs.  For example, Reuter’s Energy Correspondent, Liz Hampton, notes that oil firms operating outside the Permian basin (in Oklahoma, Colorado, Wyoming, Kansas, and parts of New Mexico) where production costs are higher may be particularly hit hard by oil prices in the $25 to $30/barrel range. On average, producers in those states need oil prices at $47 a barrel to make money. Liquidity Management and Cost StructureTo this point, we’ve addressed factors that primarily impact the demand for an OFS participant’s products and services.  Now we move to factors beyond demand – liquidity and cost structure/control.  In a pronounced industry downturn, where cash flows are known to be turning negative for an indeterminate amount of time, liquidity becomes a major focus point.  If cash runs out, a previously slow decline in business can rapidly turn into a downward spiral.  Managing the company’s liquidity can involve several related actions including reducing costs, drawing down existing lines of credit (before they become difficult to access), and engaging as soon as possible with debt providers.  While it may seem that these actions would have the same benefit to all OFS participants, the results of such efforts can vary markedly.In a pronounced industry downturn, liquidity becomes a major focus point.OFS businesses that have closely managed their line of credit, such that they have abundant LOC capacity remaining when a downturn occurs, have flexibility that other OFS businesses lack.  Likewise, OFS participants that maintain close debtor relationships are likely to get a better reception when negotiating with their debtors for adjustments to their debt structure, or for forbearance terms.In terms of cost reduction, a company’s particular cost structure plays a significant role in its ability to cut expenses.  Businesses with higher fixed costs lack the level of flexibility in cost containment that lower fixed cost businesses have.  For example, businesses in which human resources are a larger percentage of total expenses have greater flexibility when considering staff reductions, pay-cuts, furloughs, and reducing hours.  Furthermore, the ability to take those type cost containment actions can be easier for OFS businesses where the time to identify and hire qualified employees is shorter, and the cost of training such employees is lower.  These factors make it easier to take critical human resource related / cost containment actions, in that any resulting staff losses can easily be replaced, and at a lower replacement cost.Management ExperienceOur discussion of differences among OFS industry participants during a downturn, would be incomplete without addressing the benefit of a management team with deep industry experience.  Industry downcycles in highly cyclical industries,  can be even more challenging with a management team that has limited experience.  Most industries experience some degree of cyclicality, but the O&G industry tends to bring a heightened level of ups and downs, and unexpected supply and demand shifts.  Afterall, how many industries can even fathom the idea of the futures market, for their only product, pushing into the realm of negative pricing?  How many industries can be so significantly impacted, in such a short period of time, by a market share spat between market participants on the other side of the globe – not to mention those market participants being countries (Saudi Arabia and Russia) rather than individual businesses.  Not exactly an industry conducive to downturn survival if the management team has limited industry experience.In a recent management interview with one of our recurring OFS clients, the head of the company expressed how industry experience allows a seasoned management team to act quickly and decisively, and that such actions can make or break an OFS business in an industry wide downturn.  He commented that less experienced management teams sometimes suffer from a “drug” known as “hopium” – a tendency to hope that the downturn will be short lived and therefore hesitate to take the necessary decisive action needed to stave off a cash crunch that can rapidly turn into a bankruptcy filing.  He further noted that due to his teams’ deep industry experience across multiple O&G cycles, when the combined COVID-19 and Saudi-Russian dust-up hit, his team immediately, as he put it, flipped open to page 5 of their “Oh <bleep>” playbook and began a pre-planned series of actions to enhance liquidity and reduce costs, without allowing unwarranted “hope” to get in the way.  As such, their business, while certainly feeling the impact of the downturn, is feeling it much less negatively than other OFS businesses.ConclusionWhile the O&G industry has many systematic forces that impact industry participants across the board, there are many unsystematic forces that lead to marked differences in the magnitude of the downturn’s impact on individual businesses.  The OFS portion of the O&G industry is particularly diverse with subsector and basic focus potentially imposing greater, or lesser, downturn risk on a particular OFS market participant.  Beyond those demand impacting factors, cost structure and level of industry cycle, experience among management teams have a significant impact on an OFS business’s ability to hold-on during an industry wide downturn and avoid the need for a bankruptcy filing.

The determination of the appropriate “standard of value” when performing business valuations and other valuation related analyses for bankruptcy purposes is critical.  While a standard of value is often specified, it is frequently the case that the specific standard of value is not well defined in either the Bankruptcy Code, applicable state statutes, or in judicial guidance.  Further, the standard of value terminology used in valuations for bankruptcy purposes often differs from the terminology used for other (non-bankruptcy) purposes.General Standards of ValueTraditional business valuations (those for purposes other than bankruptcy) are typically performed using one of the three basic standards of value:  (1): fair market value, (2): fair value, or (3): investment value.  While some might argue that a fourth standard of value – intrinsic value – is available to business appraisers and should be included among the typical, standards of value, use of this standard of value is rarely mandated by valuation guidance, statues, or law.  Furthermore, intrinsic value (also referred to as fundamental value) is not as well defined as the other standards of value, and while mentioned in certain case law, such references rarely provide a specific definition of the standard.  As such, intrinsic value is not addressed in this article.Fair Market ValueThe most recognized and accepted standard of value in relation to business and securities valuation in the U.S. is fair market value.  Fair market value applies to nearly all federal and state income and corporate tax matters and is either the specified legal standard or guidepost of value for many other valuation purposes.  Additionally, alternative standards of value are also frequently equated to their functional equivalents under fair market value.  Although multiple definitions of fair market value exist, they are quite consistent and functionally almost identical.The definition established for fair market value in tax regulations by Treasury Regulation Section 20.2031-1(b) is as follows:The price at which the property would change hands between a willing buyer and a willing seller when the former is not under any compulsion to buy and the latter is not under any compulsion to sell, both parties having reasonable knowledge of relevant facts.A second definition of fair market value is available from the International Glossary of Business Valuation Terms as:[T]he price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm’s length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts.Yet a third definition of fair market value is provided within Section 3(18) (B) of the Employee Retirement Income Security Act wherein adequate consideration in the case of an asset for which there is no generally recognized market (e.g., stock of a closely held corporation) is defined as the fair market value of the asset as determined in good faith by the trustee or named fiduciary pursuant to the terms of the plan and in accordance with the regulations promulgated by the Secretary of Labor.  The term "fair market value" is defined in proposed section 2510.3-18(b) (2) (i) as follows:The price at which an asset would change hands between a willing buyer and a willing seller when the former is not under any compulsion to buy and the latter is not under any compulsion to sell, and both parties are able, as well as willing, to trade and are well-informed about the asset and the market for that asset.It is widely recognized that these definitions are in general agreement, particularly in regard to their common references to (i) willing buyers and sellers, (ii) lack of compulsion, and (iii) reasonable knowledge of relevant facts.  While International Glossary of Business Valuation Terms definition includes reference to (i) the hypothetical nature of the parties to the exchange, (ii) the arm’s length nature of the exchange, and (iii) an open and unrestricted market, it is widely held that these differences in the definitions are immaterial in most situations.  As such, while three commonly used definitions exist, fair market value is the most well and consistently understood of the standards of value.Fair ValueThe fair value standard of value is also commonly used by business appraisers.  Unlike fair market value, however, fair value’s different definitions are intentionally fashioned for different purposes.  Within one purpose (financial reporting), the application of fair value is quite consistent due to now well-established standards codifications issued by the Financial Accounting Standards Board (“FASB”).  In the broader legal and financial environment, the definition and or application of fair value can vary significantly from one state to another.Within the American Institute of Certified Public Accountants’ (AICPA) Statements on Standards for Valuation Services (SSVS), fair value is described as having two commonly used, albeit distinctly different definitions.Financial ReportingFor financial reporting purposes, fair value is defined under the FASB’s Accounting Standards Codification (ASC) glossary as:the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.This definition is further discussed in ASC 820 as the price being based upon a hypothetical transaction for the subject asset or liability at the measurement date, considered from the perspective of a market participant.  According to ASC 820, a market participant is: (i) an unrelated party, (ii) knowledgeable of the subject asset or liability, (iii) able to transact, and (iv) motivated but not compelled to transact.This standard of value and the definition for this standard of value is universally used for financial accounting purposes within the U.S.  Although quite similar to the definitions for fair market value in many respects, the definition of fair value for financial reporting purposes has distinct differences from the definitions for fair market value – particularly in the application of the market participant perspective.State Legal Matters (Non-Bankruptcy)In many states, fair value is the standard of value applicable by statute in regard to cases involving dissenting shareholder rights and is frequently used state minority oppression cases.[1]  However, in these settings there may be no single definition or understanding of the fair value standard of value.  Alternatively, or as an adjunct to ambiguous state statues, legal precedent may provide the primary guidance for defining fair value.Investment ValueInvestment value is much less commonly utilized by valuation practitioners than fair market value, or fair value.  Unlike fair market value and fair value, investment value is rarely a required standard of value.  It is most often used to support merger and acquisitions, or other business transaction related matters.While there is more than one definition of investment value, they are generally considered to be materially similar in meaning, albeit in part due to the definitions’ intentional lack of specificity.The International Glossary of Business Valuation Terms defines investment value as:[T]he value to a particular investor based on individual investment requirements and expectations.Note the intentional generalities and lack of constraints relative to the definitions of fair market value and the definition of fair value in regard to financial reporting matters.Similarly, albeit somewhat longer, in real estate terminology investment value is defined as:The specific value of an investment to a particular investor or class of investors based on individual investment requirement; distinguished from market value, which is impersonal and detached.[2]These two definitions of investment value are generally considered to be equivalent.Standards of Value in BankruptcyAs with fair value, the legal terminology describing the applicable standard of value for bankruptcy is not clearly defined in the U. S. Bankruptcy Code, or in applicable state statutes.[3]  Unlike standards of value outside of bankruptcy, standards of value within bankruptcy are numerous, lacking in clarity, and inconsistent.  Among the standards of value for bankruptcy purposes referenced in the Forensic & Valuation Services Practice Aid - Providing Bankruptcy and Reorganization Services, 2nd Edition Volume 2 — Valuation in Bankruptcy (F&VSPA) are:[4]Fair valuationReasonably equivalent valueIndubitable equivalentPresent fair salable valueFair consideration The sources for these standards of value include the U.S. Bankruptcy Code, The Uniform Fraudulent Transfer Act (UFTA), and The Uniform Fraudulent Conveyance Act (UFCA).  Guidance as to the definitions for these terms, or the application of the terms, are minimal, and often nonexistent, within the Code, the UFTA, or the UFCA.  Guidance as available within the Code, the UFTA, or the UFCA is as follows:[5]Fair ValuationBankruptcy Code — Fair ValuationSection 101(32) of the U.S. Bankruptcy Code defines insolvency as a:...financial condition such that the sum of such entity’s debt is greater than all of such property, at a fair valuation...Fair valuation in this context is generally interpreted by bankruptcy case law, albeit not specifically defined, as fair market value.[6]UFTA — Fair ValuationWithin the UFTA, Section 2(a) indicates, "A debtor is insolvent if the sum of the debtor’s debts is greater than all of the debtor’s assets, at a fair valuation."  The UFTA provides no definition of fair valuation, however, fair valuation is frequently analyzed similarly to fair market value when evaluating solvency.[7]Reasonably Equivalent ValueBankruptcy Code — Reasonably Equivalent ValueSection 548 of the U.S. Bankruptcy Code explains that a fraudulent transfer has occurred if a debtor has "received less than a reasonably equivalent value in exchange for such transfer or obligation." No definition of reasonably equivalent value is provided, although the Code does define value to mean "property, or satisfaction or securing of a present or antecedent debt of the debtor, but does not include an unperformed promise to furnish support to the debtor or to a relative of the debtor."[8]The F&VSPA indicates that the courts have historically considered fair market value exchanged when evaluating reasonably equivalent value.[9]  However, the U.S. Supreme Court has noted that, reasonably equivalent value is not always evaluated against a fair market value benchmark.[10]UFTA — Reasonably Equivalent ValueWhen evaluating whether a transfer was fraudulent to present and future creditors the UFTA considers whether "a reasonably equivalent value [was] exchange[d] for the transfer or obligation."[11]  The fair market value of the assets or debt exchanged is commonly considered. However, as previously referenced in regard to the U.S. Supreme Court, reasonably equivalent value is not always evaluated against a fair market value benchmark.[12]Indubitable EquivalentBankruptcy Code — Indubitable EquivalentThe U.S. Bankruptcy Code mandates that a Chapter 11 plan must be fair and equitable to all holders of secured claims.  In circumstances where the debtor’s reorganization plan is accepted over the objections of a secured creditor, the court must ensure the plan provides that secured creditors receive the indubitable equivalent of their respective claims.[13]Fair Saleable ValueUFCA — Present Fair Saleable ValueSection 2(1) of the UFCA includes a reference to the present fair saleable value of assets in considering insolvency.  Some jurisdictions have interpreted present fair saleable value to be similar to fair market value, although other jurisdictions have taken a position whereby the present fair saleable value standard imposes a reduced marketing period.[14]Fair ConsiderationUFCA — Fair ConsiderationUFCA’s Section 3 indicates that fair consideration is given for property or an obligationWhen in exchange for such property, or obligation, as a fair equivalent therefore, and in good faith, property is conveyed or an antecedent debt is satisfied, orWhen such property or obligation is received in good faith to secure a present advance or antecedent debt in amount not disproportionately small as compared with the value of the property or obligation obtained. Therefore, fair consideration is characterized as a good faith transfer whereby the debtor receives reasonably equivalent value.[15]  The fair market values exchanged are commonly used when evaluating fair consideration in states that have adopted the UFCA, as they are under the Bankruptcy Code.[16]SummaryThere is simply no clear standard of value that can be universally relied upon in the context of bankruptcy proceedings.  Standard of value terminology, definitions, and guidance within the bankruptcy realm are significantly lacking in comparison to that available to business appraisers engaged in tax and financial reporting related matters.  In the absence of clear standard of value definitions and guidance, precedent must often be relied upon.  It is therefore crucial in bankruptcy endeavors that a business appraiser have knowledge of these standard of value considerations and work closely with experienced bankruptcy attorneys in order to apply the correct standard of value to best serve their client.[1] Valuing a Business, 5th edition (Pratt, Reilly, Schweihs), p. 45 [2] The Appraisal of Real Estate, 11th edition (Chicago Appraisal Institute, 1996), p. 638. [3] Forensic & Valuation Services Practice Aid - Providing Bankruptcy and Reorganization Services, 2nd Edition Volume 2 — Valuation in Bankruptcy [4]Ibid. [5]Ibid.[6] See Andrew Johnson Properties, Inc., CCD Dec. ¶ 65, 254 (D.C. Tenn. 1974); Briden v. Foley, 776 F.2d 379, 382 (1st Cir. 1985) [7] F&VSPA [8] F&VSPA [9] Barber v. Golden Seed Co., 129 F.3d 382, 387 (7th Cir. 1997) [10] BFP v. Resolution Trust Corp., 511 U.S. 531, 548 (1994). [11] UFTA Sections 4(a)(2) and 5(a). [12] BFP v. Resolution Trust Corp., 511 U.S. 531, 548 (1994). [13] USC 1129(b)(2)(A). [14] F&VSPA [15] HBE Leasing Corp. v. Frank, 48 F.3d 623, 633 (2d Cir. 1994). [16] F&VSPA

The outbreak of the COVID-19 pandemic in the United States has caused a severe public health crisis and an unprecedented level of economic disruption.  While some economic activity is beginning to come back, predictions for longer-term negative economic impacts have also become more prevalent.  The initial thoughts of a quick V-shaped economic recovery have been replaced with a more nuanced consideration of how this situation will impact businesses within different industries and geographic areas over the next several years.  In some of the most hard-hit industries, we are already seeing what is expected to be a prolonged surge in corporate restructurings and bankruptcy filings.While some oil & gas industry bankruptcies have already occurred, expectations for many more to come are widely held.In the first half of 2020, the U.S. oil and gas industry suffered what was arguably its worst six-month period ever.  The combined impact of the Saudi/Russian price war and the drop in energy demand due to the onslaught of the COVID-19 pandemic was unprecedented.  Brent crude prices that had begun the year near $67 per barrel had dropped to $50 per barrel by early March before plummeting to $19 per barrel by the end of the quarter when the Saudi/Russia spat was in full force, but while the impact of the pandemic was still materializing.  Since the start of the pandemic, liquid fuel consumption has dropped by 15% with production levels falling 10%.  Drilling activity has been even harder hit with rig counts (active rotary rigs) now at a mere 30% of early first quarter levels.  Despite oil prices having partially recovered, oilfield activity remains anemic with the OFS industry having shed nearly 90,000 jobs through May.  While in a few areas oil and gas can be produced profitably at mid-year 2020 prices (WTI at 38.31 and Henry Hub at $1.63), most areas cannot.  Thus, while some oil & gas industry bankruptcies have already occurred, expectations for many more to come are widely held.For oil & gas companies, the decision to file for bankruptcy does not necessarily signal the demise of the business.  If executed properly, Chapter 11 reorganization affords a financially distressed or insolvent company an opportunity to restructure its liabilities and emerge from the proceedings as a viable going concern.  Along with a bankruptcy filing (more typically before and/or in preparation for the filing), the company usually undertakes a strategic review of its operations, including opportunities to shed assets or even lines of business.  During the reorganization proceeding, stakeholders, including creditors and equity holders, negotiate and litigate to establish economic interests in the emerging entity.  The Chapter 11 reorganization process concludes when the bankruptcy court confirms a reorganization plan that both specifies a reorganization value and reflects the agreed upon strategic direction and capital structure of the emerging entity.In addition to fulfilling technical requirements of the bankruptcy code and providing adequate disclosure, two characteristics of a reorganization plan are germane from a valuation perspective:11. The plan should demonstrate that the economic outcomes for any consenting stakeholders are superior under Chapter 11 proceeding compared to a Chapter 7 proceeding, which provides for more direct relief through a liquidation of the business. This is generally referred to as the “best interests test.”2. The plan should demonstrate that, upon confirmation by the bankruptcy court, it will not likely result in liquidation or further reorganization of the business. This is generally referred to as the “cash flow test.”Finally, upon emerging from bankruptcy, companies are required to apply “fresh start” accounting, under which all assets of the company, including identifiable intangible assets, are recorded on the balance sheet at fair value.Best Interests TestWithin this context of a best interests test, valuation specialists can provide useful financial advice to:Establish the value of the business under a Chapter 7 liquidation premise.Measure the reorganization value of a business, which, absent liquidation, represents the economic “pie” from which stakeholder claims can be satisfied. A plan confirmed by a bankruptcy court should establish a reorganization value that exceeds the value of the company under a liquidation premise.A Floor Value: Liquidation ValueIf a company can no longer pay its debts and does not restructure, it will undergo Chapter 7 liquidation.  The law generally mandates that Chapter 11 restructuring only be approved if it provides a company’s creditors with their highest level of expected repayment.  The Chapter 11 restructuring plan must be in the best interest of the creditors (relative to Chapter 7 liquidation) in order for it to be approved.  Given this understanding of the law, the first valuation step in successful Chapter 11 restructuring is assessing the alternative, liquidation value. This value will be a threshold that any reorganization plan must outperform in order to be accepted by the court.The value in liquidating a business is unfortunately not as simple as finding the fair market value, or even a book value for all the assets.  The liquidation premise generally contemplates a sale of the company’s assets within a short period.  Any valuation must account for the fact that inadequate time to place the assets in the open market means that the price obtained is usually lower than the fair market value.  Everyone has seen the “inventory liquidation sale” sign or the “going out of business” sign in the shop window.  Experience tells us that the underlying “marketing period” assumptions made in a liquidation analysis can have a material impact on the valuation conclusion.Liquidation value can occur under three sub-sets: assemblage of assets, orderly liquidation, and forced liquidation.From a technical perspective, liquidation value can occur under three sub-sets: assemblage of assets, orderly liquidation, and forced liquidation.  As implied, these are asset-based approaches to valuation that differ in their assumptions surrounding the marketing period and manner in which the assets are disposed.  There are no strict guidelines in the bankruptcy process related to these three sub-sets; bankruptcy courts generally determine the applicable premise of value on a case by case basis.  The determination (and support) of the appropriate premise can be an important component of the best interests test.In general, the discount from fair market value implied by the price obtainable under a liquidation premise is related to the liquidity of an asset.  Accordingly, valuation analysts often segregate the assets of the petitioner company into several categories based upon the ease of disposal.  Liquidation value is estimated for each category by referencing available discount benchmarks.  For example, no haircut would typically be applied to cash and equivalents, while less liquid assets (such as accounts receivable or inventory) would likely incur potentially significant discounts.  For some assets categories, the appropriate level of discount can be estimated by analyzing the prices commanded in the sale of comparable assets under a similarly distressed sale scenario.  Within the oil & gas industry, the operating assets come in many varieties, from oil & gas reserves, industry-specific well-site equipment and midstream assets, and less industry-specific equipment utilized by oilfield service providers.Reorganization ValueOnce an accurate liquidation value is established, the next step is determining whether the company can be reorganized in a way that provides more value to a company’s stakeholders than discounted asset sales.ASC 852 defines reorganization value as:2The value attributable to the reconstituted entity, as well as the expected net realizable value of those assets that will be disposed of before reconstitution occurs. This value is viewed as the value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring.Typically, the “value attributable to the reconstituted entity” (i.e., the new enterprise value for the restructured business) is the largest element of the total reorganization value.  Unlike a liquidation, this enterprise value falls under what valuation professionals call a “going concern” value premise.  This means that the business is valued based on the return that would be generated by the future operations of the emerging, restructured entity and not what one would be paid for selling individual assets.  The intangible elements of going concern value result from factors such as having a trained workforce, a loyal customer base, an operational plant, and the necessary licenses, systems, and procedures in place.  To measure enterprise value in this way, reorganization plans primarily use a type of income approach, the discounted cash flow (DCF) method.  The DCF method estimates the net present value of future cash flows that the emerging entity is expected to generate.  Implementing the discounted cash flow methodology requires three basic elements:1. Forecast of Expected Future Cash Flows. Guidance from management can be critical in developing a supportable cash flow forecast. Generally, valuation specialists develop cash flow forecasts for discrete periods that may range from three to ten years, or in the case of upstream companies, the economic life of the company’s reserves. Conceptually, one would forecast discrete cash flows for as many periods as necessary until a stabilized cash flow stream can be anticipated.  Due to the opportunity to make broad strategic changes as part of the reorganization process, cash flows from the emerging entity must be projected for the period when the company expects to execute its restructuring and transition plans.  Major drivers of the cash flow forecast include projected revenue, gross margins, operating costs and capital expenditure requirements.  The historical experience of the petitioner company, as well as information from publicly traded companies operating in similar lines of business, can provide reference points to evaluate each element of the cash flow forecast.2. Terminal Value. The terminal value captures the value of all cash flows after the discrete forecast period. Terminal value is determined by using assumptions about long-term cash flow growth rate and the discount rate to capitalize cash flow at the end of the forecast period.  This means that the model takes the cash flow value for the last discrete year, and then grows it at a constant rate for perpetuity.  In some cases, the terminal value may be estimated by applying current or projected market multiples to the projected results in the last discrete year. An average EV/EBITDA of comparable companies, for instance, might be used to find a likely market value of the business at that date.  For upstream oil & gas companies, a terminal value is typically not utilized given the finite nature of the underlying resource.  Instead, the discrete cash flows are projected for the entire economic life of the reserves.3. Discount Rate. The discount rate is used to estimate the present value of the forecasted cash flows. Valuation analysts develop a suitable discount rate using assumptions about the costs of equity and debt capital, and the capital structure of the emerging entity.  Costs of equity capital are usually estimated by utilizing a build-up method that uses the long-term risk-free rate, equity risk premia, and other industry or company-specific factors as inputs.  The cost of debt capital and the likely capital structure may be based on benchmark rates on similar issues and the structures of comparable companies.  Overall, the discount rate should reasonably reflect the operational and market risks associated with the expected cash flows of the emerging entity.The sum of the present values of all the forecasted cash flows, including discrete period cash flows and the terminal value (if appropriate), provides an indication of the business enterprise value of the emerging entity for a specific set of forecast assumptions.  The reorganization value is the sum of that expected business enterprise value of the emerging entity and proceeds from any sale or other disposal of assets during the reorganization. Since the DCF-determined part of this value relies on so many forecast assumptions, different stakeholders may independently develop distinct estimates of the reorganization value to facilitate negotiations or litigation.  The eventual confirmed reorganization plan, however, reflects the terms agreed upon by the consenting stakeholders and specifies either a range of reorganization values or a single point estimate.In conjunction with the reorganization plan, the courts also approve the amounts of allowed claims or interests for the stakeholders in the restructuring entity.  From the perspective of the stakeholders, the reorganization value represents all of the resources available to meet the post-petition liabilities (liabilities from continued operations during restructuring) and allowed claims and interests called for in the confirmed reorganization plan.  If this agreed upon reorganization value exceeds the value to the stakeholders of the liquidation, then there is only one more valuation hurdle to be cleared: a cash flow test.  This is an examination of whether the restructuring creates a company that will be viable for the long term—that is not likely to be back in bankruptcy court in a few years.Cash Flow TestFor a company that passes the best interest test, this second requirement represents the last valuation hurdle to successfully emerging from Chapter 11 restructuring. Within the context of a cash flow test, valuation specialists can demonstrate the viability of the emerging entity’s proposed capital structure, including debt amounts and terms given the stream of cash flows that can be reasonably expected from the business.  The cash flow test essentially represents a test of the company’s current and projected future financial solvency.The cash flow test essentially represents a test of the company’s current and projected future financial solvency.Even if a company shows that the restructuring plan will benefit stakeholders relative to liquidation, the court will still reject the plan if it is likely to lead to liquidation or further restructuring in the foreseeable future.  To satisfy the court, a cash flow test is used to analyze whether the restructured company would generate enough cash to consistently pay its debts.  This cash flow test can be broken into three parts.The first step in conducting the cash flow test is to identify the cash flows that the restructured company will generate.  These cash flows are available to service all the obligations of the emerging entity.  A stream of cash flows is developed using the DCF method in order to determine the reorganization value.  Thus, in practice, establishing the appropriate stream of cash flows for the cash flow test is often a straightforward matter of using these projected cash flows in the new model.Once the fundamental cash flow projections are incorporated, analysts then model the negotiated or litigated terms attributable to the creditors of the emerging entity.  This involves projecting interest and principal payments to the creditors, including any amounts due to providers of short term, working capital facilities.  These are the payments for each period that the cash flow generated up to that point must be able to cover in order for the company to avoid another bankruptcy.The cash flows of the company will not be used only to pay debts, and so the third and final step in the cash flow test is documenting the impact of the net cash flows on the entire balance sheet of the emerging entity.  This entails modeling changes in the company’s asset base as portions of the expected cash flows are invested in working capital and capital equipment, and modeling changes in the debt obligations of and equity interests in the company as the remaining cash flows are disbursed to the capital providers.A reorganization plan is generally considered viable if such a detailed cash flow model indicates solvent operations for the foreseeable future.  The answer, however, is typically not so simple as assessing a single cash flow forecast.  It is a rare occurrence when management’s base case forecast does not pass the cash flow test.  The underpinnings of the entire reorganization plan are based on this forecast, so it is almost certain that the cash flow projections have been produced with an eye toward meeting this requirement.  Viability is proven not only by passing the cash flow test on a base case scenario, but also maintaining financial viability under some set of reasonable projections in which the company (or industry, or general economy) underperforms the base level of expectations.  This “stress-testing” of the company’s financial projection is a critical component of a meaningful cash flow test.“Fresh Start” AccountingCompanies emerging from Chapter 11 bankruptcy are required to re-state their balance sheets to conform to the reorganization value and plan.On the left side of the balance sheet, emerging companies need to allocate the reorganization value to the various tangible and identifiable intangible assets the post-bankruptcy company owns. To the extent the reorganization value exceeds the sum of the fair value of individual identifiable assets, the balance is recorded as goodwill.On the right side of the balance sheet, the claims of creditors are re-stated to conform to the terms of the reorganization plan. Implementing “fresh start” accounting requires valuation expertise to develop reasonably accurate fair value measurements. ConclusionAlthough the Chapter 11 process can seem burdensome, a rigorous assessment of cash flows, and a company’s capital structure can help the company as it develops a plan for years of future success.  We hope that this explanation of the key valuation-related steps of a Chapter 11 restructuring helps managers realize this potential.However, we also understand that executives of oil & gas companies going through a Chapter 11 restructuring process need to juggle an extraordinary set of additional responsibilities—evaluating alternate strategies, implementing new and difficult business plans, and negotiating with various stakeholders.  Given executives’ multitude of other responsibilities, they often decide that it is best to seek help from outside, third party specialists. Valuation specialists can relieve some of the burden from executives by developing the valuation and financial analysis necessary to satisfy the requirements for a reorganization plan to be confirmed by a bankruptcy court.  Specialists can also provide useful advice and perspective during the negotiation of the reorganization plan to help the company emerge with the best chance of success.With years of experience in both oil & gas and in advising companies through the bankruptcy process, Mercer Capital’s professionals are well-positioned to help in both of these roles.  For a confidential conversation about your company’s current financial position and how we might assist in your bankruptcy-related analyses, please contact a Mercer Capital professional.1 Accounting Standards Codification Topic 852, Reorganizations (“ASC 852”). ASC 852-05-8.2 ASC 852-10-20.

The outbreak of the COVID-19 pandemic in the United States has caused a severe public health crisis and an unprecedented level of economic disruption.  While some economic activity is beginning to come back, predictions for longer-term negative economic impacts have also become more prevalent.  The initial thoughts of a quick V-shaped economic recovery have been replaced with a more nuanced consideration of how this situation will impact businesses within different industries and geographic areas over the next several years.  In some of the most hard-hit industries, we are already seeing what is expected to be a prolonged surge in corporate restructurings and bankruptcy filings.While some oil & gas industry bankruptcies have already occurred, expectations for many more to come are widely held.In the first half of 2020, the U.S. oil and gas industry suffered what was arguably its worst six-month period ever.  The combined impact of the Saudi/Russian price war and the drop in energy demand due to the onslaught of the COVID-19 pandemic was unprecedented.  Brent crude prices that had begun the year near $67 per barrel had dropped to $50 per barrel by early March before plummeting to $19 per barrel by the end of the quarter when the Saudi/Russia spat was in full force, but while the impact of the pandemic was still materializing.  Since the start of the pandemic, liquid fuel consumption has dropped by 15% with production levels falling 10%.  Drilling activity has been even harder hit with rig counts (active rotary rigs) now at a mere 30% of early first quarter levels.  Despite oil prices having partially recovered, oilfield activity remains anemic with the OFS industry having shed nearly 90,000 jobs through May.  While in a few areas oil and gas can be produced profitably at mid-year 2020 prices (WTI at 38.31 and Henry Hub at $1.63), most areas cannot.  Thus, while some oil & gas industry bankruptcies have already occurred, expectations for many more to come are widely held.For oil & gas companies, the decision to file for bankruptcy does not necessarily signal the demise of the business.  If executed properly, Chapter 11 reorganization affords a financially distressed or insolvent company an opportunity to restructure its liabilities and emerge from the proceedings as a viable going concern.  Along with a bankruptcy filing (more typically before and/or in preparation for the filing), the company usually undertakes a strategic review of its operations, including opportunities to shed assets or even lines of business.  During the reorganization proceeding, stakeholders, including creditors and equity holders, negotiate and litigate to establish economic interests in the emerging entity.  The Chapter 11 reorganization process concludes when the bankruptcy court confirms a reorganization plan that both specifies a reorganization value and reflects the agreed upon strategic direction and capital structure of the emerging entity.In addition to fulfilling technical requirements of the bankruptcy code and providing adequate disclosure, two characteristics of a reorganization plan are germane from a valuation perspective:11. The plan should demonstrate that the economic outcomes for any consenting stakeholders are superior under Chapter 11 proceeding compared to a Chapter 7 proceeding, which provides for more direct relief through a liquidation of the business. This is generally referred to as the “best interests test.”2. The plan should demonstrate that, upon confirmation by the bankruptcy court, it will not likely result in liquidation or further reorganization of the business. This is generally referred to as the “cash flow test.”Finally, upon emerging from bankruptcy, companies are required to apply “fresh start” accounting, under which all assets of the company, including identifiable intangible assets, are recorded on the balance sheet at fair value.Best Interests TestWithin this context of a best interests test, valuation specialists can provide useful financial advice to:Establish the value of the business under a Chapter 7 liquidation premise.Measure the reorganization value of a business, which, absent liquidation, represents the economic “pie” from which stakeholder claims can be satisfied. A plan confirmed by a bankruptcy court should establish a reorganization value that exceeds the value of the company under a liquidation premise.A Floor Value: Liquidation ValueIf a company can no longer pay its debts and does not restructure, it will undergo Chapter 7 liquidation.  The law generally mandates that Chapter 11 restructuring only be approved if it provides a company’s creditors with their highest level of expected repayment.  The Chapter 11 restructuring plan must be in the best interest of the creditors (relative to Chapter 7 liquidation) in order for it to be approved.  Given this understanding of the law, the first valuation step in successful Chapter 11 restructuring is assessing the alternative, liquidation value. This value will be a threshold that any reorganization plan must outperform in order to be accepted by the court.The value in liquidating a business is unfortunately not as simple as finding the fair market value, or even a book value for all the assets.  The liquidation premise generally contemplates a sale of the company’s assets within a short period.  Any valuation must account for the fact that inadequate time to place the assets in the open market means that the price obtained is usually lower than the fair market value.  Everyone has seen the “inventory liquidation sale” sign or the “going out of business” sign in the shop window.  Experience tells us that the underlying “marketing period” assumptions made in a liquidation analysis can have a material impact on the valuation conclusion.Liquidation value can occur under three sub-sets: assemblage of assets, orderly liquidation, and forced liquidation.From a technical perspective, liquidation value can occur under three sub-sets: assemblage of assets, orderly liquidation, and forced liquidation.  As implied, these are asset-based approaches to valuation that differ in their assumptions surrounding the marketing period and manner in which the assets are disposed.  There are no strict guidelines in the bankruptcy process related to these three sub-sets; bankruptcy courts generally determine the applicable premise of value on a case by case basis.  The determination (and support) of the appropriate premise can be an important component of the best interests test.In general, the discount from fair market value implied by the price obtainable under a liquidation premise is related to the liquidity of an asset.  Accordingly, valuation analysts often segregate the assets of the petitioner company into several categories based upon the ease of disposal.  Liquidation value is estimated for each category by referencing available discount benchmarks.  For example, no haircut would typically be applied to cash and equivalents, while less liquid assets (such as accounts receivable or inventory) would likely incur potentially significant discounts.  For some assets categories, the appropriate level of discount can be estimated by analyzing the prices commanded in the sale of comparable assets under a similarly distressed sale scenario.  Within the oil & gas industry, the operating assets come in many varieties, from oil & gas reserves, industry-specific well-site equipment and midstream assets, and less industry-specific equipment utilized by oilfield service providers.Reorganization ValueOnce an accurate liquidation value is established, the next step is determining whether the company can be reorganized in a way that provides more value to a company’s stakeholders than discounted asset sales.ASC 852 defines reorganization value as:2The value attributable to the reconstituted entity, as well as the expected net realizable value of those assets that will be disposed of before reconstitution occurs. This value is viewed as the value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring.Typically, the “value attributable to the reconstituted entity” (i.e., the new enterprise value for the restructured business) is the largest element of the total reorganization value.  Unlike a liquidation, this enterprise value falls under what valuation professionals call a “going concern” value premise.  This means that the business is valued based on the return that would be generated by the future operations of the emerging, restructured entity and not what one would be paid for selling individual assets.  The intangible elements of going concern value result from factors such as having a trained workforce, a loyal customer base, an operational plant, and the necessary licenses, systems, and procedures in place.  To measure enterprise value in this way, reorganization plans primarily use a type of income approach, the discounted cash flow (DCF) method.  The DCF method estimates the net present value of future cash flows that the emerging entity is expected to generate.  Implementing the discounted cash flow methodology requires three basic elements:1. Forecast of Expected Future Cash Flows. Guidance from management can be critical in developing a supportable cash flow forecast. Generally, valuation specialists develop cash flow forecasts for discrete periods that may range from three to ten years, or in the case of upstream companies, the economic life of the company’s reserves. Conceptually, one would forecast discrete cash flows for as many periods as necessary until a stabilized cash flow stream can be anticipated.  Due to the opportunity to make broad strategic changes as part of the reorganization process, cash flows from the emerging entity must be projected for the period when the company expects to execute its restructuring and transition plans.  Major drivers of the cash flow forecast include projected revenue, gross margins, operating costs and capital expenditure requirements.  The historical experience of the petitioner company, as well as information from publicly traded companies operating in similar lines of business, can provide reference points to evaluate each element of the cash flow forecast.2. Terminal Value. The terminal value captures the value of all cash flows after the discrete forecast period. Terminal value is determined by using assumptions about long-term cash flow growth rate and the discount rate to capitalize cash flow at the end of the forecast period.  This means that the model takes the cash flow value for the last discrete year, and then grows it at a constant rate for perpetuity.  In some cases, the terminal value may be estimated by applying current or projected market multiples to the projected results in the last discrete year. An average EV/EBITDA of comparable companies, for instance, might be used to find a likely market value of the business at that date.  For upstream oil & gas companies, a terminal value is typically not utilized given the finite nature of the underlying resource.  Instead, the discrete cash flows are projected for the entire economic life of the reserves.3. Discount Rate. The discount rate is used to estimate the present value of the forecasted cash flows. Valuation analysts develop a suitable discount rate using assumptions about the costs of equity and debt capital, and the capital structure of the emerging entity.  Costs of equity capital are usually estimated by utilizing a build-up method that uses the long-term risk-free rate, equity risk premia, and other industry or company-specific factors as inputs.  The cost of debt capital and the likely capital structure may be based on benchmark rates on similar issues and the structures of comparable companies.  Overall, the discount rate should reasonably reflect the operational and market risks associated with the expected cash flows of the emerging entity.The sum of the present values of all the forecasted cash flows, including discrete period cash flows and the terminal value (if appropriate), provides an indication of the business enterprise value of the emerging entity for a specific set of forecast assumptions.  The reorganization value is the sum of that expected business enterprise value of the emerging entity and proceeds from any sale or other disposal of assets during the reorganization. Since the DCF-determined part of this value relies on so many forecast assumptions, different stakeholders may independently develop distinct estimates of the reorganization value to facilitate negotiations or litigation.  The eventual confirmed reorganization plan, however, reflects the terms agreed upon by the consenting stakeholders and specifies either a range of reorganization values or a single point estimate.In conjunction with the reorganization plan, the courts also approve the amounts of allowed claims or interests for the stakeholders in the restructuring entity.  From the perspective of the stakeholders, the reorganization value represents all of the resources available to meet the post-petition liabilities (liabilities from continued operations during restructuring) and allowed claims and interests called for in the confirmed reorganization plan.  If this agreed upon reorganization value exceeds the value to the stakeholders of the liquidation, then there is only one more valuation hurdle to be cleared: a cash flow test.  This is an examination of whether the restructuring creates a company that will be viable for the long term—that is not likely to be back in bankruptcy court in a few years.Cash Flow TestFor a company that passes the best interest test, this second requirement represents the last valuation hurdle to successfully emerging from Chapter 11 restructuring. Within the context of a cash flow test, valuation specialists can demonstrate the viability of the emerging entity’s proposed capital structure, including debt amounts and terms given the stream of cash flows that can be reasonably expected from the business.  The cash flow test essentially represents a test of the company’s current and projected future financial solvency.The cash flow test essentially represents a test of the company’s current and projected future financial solvency.Even if a company shows that the restructuring plan will benefit stakeholders relative to liquidation, the court will still reject the plan if it is likely to lead to liquidation or further restructuring in the foreseeable future.  To satisfy the court, a cash flow test is used to analyze whether the restructured company would generate enough cash to consistently pay its debts.  This cash flow test can be broken into three parts.The first step in conducting the cash flow test is to identify the cash flows that the restructured company will generate.  These cash flows are available to service all the obligations of the emerging entity.  A stream of cash flows is developed using the DCF method in order to determine the reorganization value.  Thus, in practice, establishing the appropriate stream of cash flows for the cash flow test is often a straightforward matter of using these projected cash flows in the new model.Once the fundamental cash flow projections are incorporated, analysts then model the negotiated or litigated terms attributable to the creditors of the emerging entity.  This involves projecting interest and principal payments to the creditors, including any amounts due to providers of short term, working capital facilities.  These are the payments for each period that the cash flow generated up to that point must be able to cover in order for the company to avoid another bankruptcy.The cash flows of the company will not be used only to pay debts, and so the third and final step in the cash flow test is documenting the impact of the net cash flows on the entire balance sheet of the emerging entity.  This entails modeling changes in the company’s asset base as portions of the expected cash flows are invested in working capital and capital equipment, and modeling changes in the debt obligations of and equity interests in the company as the remaining cash flows are disbursed to the capital providers.A reorganization plan is generally considered viable if such a detailed cash flow model indicates solvent operations for the foreseeable future.  The answer, however, is typically not so simple as assessing a single cash flow forecast.  It is a rare occurrence when management’s base case forecast does not pass the cash flow test.  The underpinnings of the entire reorganization plan are based on this forecast, so it is almost certain that the cash flow projections have been produced with an eye toward meeting this requirement.  Viability is proven not only by passing the cash flow test on a base case scenario, but also maintaining financial viability under some set of reasonable projections in which the company (or industry, or general economy) underperforms the base level of expectations.  This “stress-testing” of the company’s financial projection is a critical component of a meaningful cash flow test.“Fresh Start” AccountingCompanies emerging from Chapter 11 bankruptcy are required to re-state their balance sheets to conform to the reorganization value and plan.On the left side of the balance sheet, emerging companies need to allocate the reorganization value to the various tangible and identifiable intangible assets the post-bankruptcy company owns. To the extent the reorganization value exceeds the sum of the fair value of individual identifiable assets, the balance is recorded as goodwill.On the right side of the balance sheet, the claims of creditors are re-stated to conform to the terms of the reorganization plan. Implementing “fresh start” accounting requires valuation expertise to develop reasonably accurate fair value measurements. ConclusionAlthough the Chapter 11 process can seem burdensome, a rigorous assessment of cash flows, and a company’s capital structure can help the company as it develops a plan for years of future success.  We hope that this explanation of the key valuation-related steps of a Chapter 11 restructuring helps managers realize this potential.However, we also understand that executives of oil & gas companies going through a Chapter 11 restructuring process need to juggle an extraordinary set of additional responsibilities—evaluating alternate strategies, implementing new and difficult business plans, and negotiating with various stakeholders.  Given executives’ multitude of other responsibilities, they often decide that it is best to seek help from outside, third party specialists. Valuation specialists can relieve some of the burden from executives by developing the valuation and financial analysis necessary to satisfy the requirements for a reorganization plan to be confirmed by a bankruptcy court.  Specialists can also provide useful advice and perspective during the negotiation of the reorganization plan to help the company emerge with the best chance of success.With years of experience in both oil & gas and in advising companies through the bankruptcy process, Mercer Capital’s professionals are well-positioned to help in both of these roles.  For a confidential conversation about your company’s current financial position and how we might assist in your bankruptcy-related analyses, please contact a Mercer Capital professional.1 Accounting Standards Codification Topic 852, Reorganizations (“ASC 852”). ASC 852-05-8.2 ASC 852-10-20.

It’s been a truly dizzying time in the world of international oil production over the last five weeks.  With so much macroeconomic activity, twists and turns, it’s been easy to fall behind as to “what’s gone on”, and for even those who’ve been paying reasonably good attention, you may not be sure what all has occurred.  What suggestions were made? What deals were cut?  What cooperation was gained?  What threats were made, and who, if anyone, “blinked”?  To some extent, we may never know the answers to all those questions.How We Got HereSo, what occurred in the last few months that got us to this very dynamic point in time?  To summarize:January-February 2020 – The coronavirus “goes” pandemic, spreading throughout the world.  While the full extent of damage from the pandemic remains unknown, it’s expected that at least 2 million people will contract the virus, the death toll will easily surpass 120,000 and the economic damage will be of a magnitude that hasn’t been seen in several generations.  Due to the need for quarantines, travel restrictions, forced business shutdowns and stay-at-home orders to limit the spread and speed of the spread, oil demand plunged and oil prices sagged.March 6, 2020 – The three-year OPEC+ (OPEC represented by Saudi Arabia and “+” effectively meaning Russia) production/price cooperation pact, set to expire on March 31, fell apart when Moscow refused to support Riyadh’s demand for additional production cuts aimed to offset the reduced demand for oil resulting from the coronavirus pandemic.March 8, 2020 – So what do two strong-willed centrally-run countries do when their oil production control negotiations (for the purpose of supporting oil prices, on which both countries rely) break-down?  Keep negotiating?  Give-in a little for their mutual good?  No.  Instead they purposefully shove their thumb into the other party’s eye by boosting production?  Make sense?  Not really.  Unless there are ulterior motives in-play such as, curbing the U.S. shale revolution that buoyed the U.S. to energy/oil independence and the top spot in world oil production.  Not a certain motivation, but a potential motivation that has a lot of people talking about the possibility. Late March 2020 – At this point, Covid-19 has significantly reduced oil demand.  In the meantime, the Saudis and the Russians have boosted oil production and oil prices have tanked.  The U.S.’s shale producers are in free fall with bankruptcies staring them in the face.  U.S. energy independence and oil production leadership are in the crosshairs and the Saudis and Russians are showing no signs of any rational behavior on energy production.  Here’s where the geopolitical, oil-production-tied-relationships game starts to get “interesting”. What’s a Newly Leading Oil Producer With a Threatened Leading Position to Do?It’s at this point that all sorts of possible actions on the part of the U.S. begin to be discussed.  Various suggested actions include:Lure Saudi Arabia away from OPEC and into a production-setting relationship with the U.S. – This one was simply a bit hard to imagine having much of a chance at all.  First, the U.S. has always been very critical of production controlling cartels, and production setting with the Saudis would be the exact opposite of our long-held free-market values.  Second, U.S. anti-trust laws simply wouldn’t allow the U.S. government to engage in limiting production, or oil companies to join together for the purpose of controlling oil production.That being said, the Wall Street Journal reported in late March that officials at the Energy Department were seeking to convince the Trump administration to push for Saudi Arabia to quit OPEC and work with the U.S. to stabilize oil prices.  At the same time, Hart Energy was reporting that Energy Secretary Dan Brouillette had indicated that he didn’t know if a U.S.-Saudi oil alliance was going to be presented as a path forward in any formal way as a part of the public policy process, and that no decisions regarding any such alliance had been made.  However, it was also reported that the Trump administration would soon send a special energy representative from the Energy Department, to Saudi Arabia, in order to improve talks between the two countries.  Brouillette also indicated that the Trump administration would at some point engage in some sort of diplomatic effort with Saudi Arabia and Russia on oil production levels and that he would work with Secretary of State Mike Pompeo and other officials on that effort.  This all left the likelihood U.S.-Saudi cooperation open to individual interpretation.U.S. Production Limits Via the Texas Railroad CommissionAlthough the U.S. government may be prohibited from entering into oil production agreements by anti-trust laws, that’s not the case for individual states.  In late March, reports began to surface of the Texas Railroad Commission having been approached by two major Texas oil producers with the idea of negotiating for production limits with OPEC.  The Texas Railroad Commission?  Despite the Commission’s name, it long ago ceased any regulation pertaining to the railroads, however, its regulation of Texas oil production (control granted to it back in 1919) continues to this day.  Although the Commission has long had a reputation for markedly lenient regulation of production levels, the current crisis has powerful voices calling for the Commission to consider working with OPEC to reduce production levels in order to save the U.S. oil industry from the devastating impact of sub-$25/barrel oil prices.While this may pose a “workable” process, it comes with multiple layers of required cooperation and agreements.  Does the Commission address OPEC directly, or through the Trump administration?  OPEC itself requires member cooperation, and the Commission would need the cooperation of other U.S. oil producing states.  After all, if the Commission limited production in Texas, but such limits simply triggered higher output in other U.S. states, the effort would be for naught.  President of the Texas Oil & Gas Association (TXOGA), Todd Staples, commented on that very matter indicating that if Texas oil and gas operators cut back production in isolation, that reduced production would likely be filled by operators producing in other states.Even if the Commission’s involvement gained the necessary cooperation from the Trump Administration, OPEC and other states, the idea faces headwinds both from a purely practical standpoint and from those that simply don’t want the Commission involved in the production quotas.  Some additional items on the practical side of things:Wayne Christian, the Commission’s Chairman, noted that the Commission hasn’t imposed such limits in more than 40 years, the Commission doesn’t have staff with any experience in implementing production limits, the Commission would have to track production across thousands of independent producers, and the Commission’s technological capabilities for handling such a process are quite limited.The Commission’s next meeting was, at that time, weeks away on April 21st, meaning that no action in pursuit of limiting production levels would occur for some time.Other high oil producing states, unlike Texas, don’t have similar regulatory bodies to the Texas Railroad Commission. Without such regulatory bodies, those states may not have the ability to effectively limit in-state oil production. Even if these practical barriers could be overcome, there remain powerful voices that are opposed to any moves that go beyond market forces.  Mike Sommers, the CEO of the American Petroleum Institute, has pushed back against proposals that would involve U.S. officials negotiating a joint production cut with OPEC and Russia.  Sommers noted that the U.S. has always supported the market as the determinant of oil prices, and that during times of crisis, those principles shouldn’t be abandoned.  Sommers was particularly opposed to the proposal from a Texas Railroad Commission commissioner, that would regulate oil production within Texas.  Commissioner Sommers further indicated that any such proposal would be damaging to our posture in the world, and that imposing a production quota on Texas produced oil would penalize the most efficient producers while supporting less efficient companies.  Frank Macchiarola, Senior Vice President of Policy, Economics and Regulatory Affairs at the American Petroleum Institute echoed Sommers sentiments indicating that the Institute's position is very simple– quotas are bad.  He added that quotas have been proven to be ineffective and harmful, and that there’s no reason at this time to be imitating OPEC. However, Texas Railroad Commission commissioner Ryan Sitton noted that he’d already spoken with OPEC Secretary-General Mohammad Barkindo regarding an international agreement that would ensure economic stability as the world recovers from the coronavirus outbreak. Sitton stated that Barkindo had invited the commissioner to OPEC’s meeting in June to further discuss the matter.  Commissioner Sitton further noted that international cooperation was absolutely necessary if Texas were to decide to limit production.  He commented that if Texas limited production as part of an international agreement to balance the markets, he thought the odds of success would be very good.  However, he further noted that if reductions were only implemented by Texas, without collaboration with others, the odds of success were near zero.Forget the “Carrot”, Use the StickOf course, there’s always those in favor of the straight-forward approach to motivating others to a preferred course of action through of the “stick”, rather than the “carrot”.  Especially those that view the Saudi-Russian production spikes as an overt attempt to damage the U.S. shale oil industry.  Senators, including Lisa Murkowski of Alaska and John Hoeven of North Dakota, noted that the American people are not without recourse in responding to the Saudi-Russian actions.  They’ve noted that tariffs and other trade restrictions, investigations, safeguard actions, sanctions, and much else are within the arsenal of potential responses.  Another similarly minded suggestion is to remove U.S. armed forces from the Saudi kingdom.Others, such as oil industry analyst Ellen Wald indicate that the best option for U.S. in this situation is for the Trump administration to pursue diplomatic efforts to settle things down.  Wald noted that sanctions and embargoes aren’t realistic and will having a negative impact for the United States.  Sitton seemed to concur with Wald’s position indicating that a diplomatic solution and planned production cuts would be better for everyone.  He added that although the Trump administration could embargo Russian and Saudi oil as a form of punishment, his hope was that we don’t end-up going there.Interestingly, suggested use of these more “stick” type actions have not been coming from the Trump administration.  Instead, President Trump has remained more measured in his comments, only noting that if the Saudis and Russians didn’t resolve the matter on their own in short-order, that he would get involved at the appropriate time.The Art of the DealPresident Trump, ever the deal-maker, may be looking to a solution that avoids violation of the U.S. anti-trust laws, sidesteps brokering a deal on behalf of the Texas Railroad Commission and doesn’t include the actual application of any “stick” – although maybe using the threat of the “stick.”  Within the last week, President Trump tweeted that he expected Russia and Saudi Arabia to agree to cut production by millions of barrels a day.  Although the Kremlin soon thereafter denied any talks with the Saudis, officials from the kingdom then noted that they would consider significant production cuts as long as other members in the G-20 group of nations were willing to join the effort.  On April 9, OPEC and Russia announced plans to reduce their oil production by more than 20%, albeit also indicating that they expect the U.S. and other top producers to join the effort to prop-up prices.  U.S. officials noted that while they had not committed to any specific cuts in production, expectations were that U.S. output would fall substantially over the next two years, sounding ever so much like the U.S. is on-board with participating in the reductions, albeit without crossing the line into anti-trust law triggering commitments.  However, one sticking point to the agreement was Mexico, who on April 10 balked at the plan.  Mexican President Lopez Obrador refused to sign-off on the agreement as it would necessitate putting his plans for Pemex’s revival on hold.  That resulted in Obrador getting a call from President Trump from which the U.S. seemed to be offering to take part of Mexico’s required production cut with some sort of undefined “repayment” to occur at a later date.   Ultimately, a deal was reached, with OPEC+ nations agreeing to reduce output by 9.7 million barrels per day, representing approximately 10% of global demand before the coronavirus pandemic.  However, with demand down an estimated 35%, the cut does not fully balance supply and demand.  Oil prices were largely unchanged on the news of the agreement.Conclusion, or Lack ThereofAs we indicated, it’s been a truly dizzying time in the rough-n-tumble world of oil production.  Like they say, if you miss a day, you miss a lot.  For now, it at least appears that someone may have just blinked.  The Trump administration seems to be on the verge of a truly historic deal to cut worldwide oil production and bring oil prices up to a modestly workable level.  And that with the U.S. not committing to forcing domestic producers to cut production levels but indicating that U.S. production would “naturally” decline without the government’s intervention.  That coupled with a potential side-deal with Mexico to “cover” part of the production decrease that was being sought from that country, but that Mexico is unwilling to shoulder on its own.  Will it work?  Will the deal be accomplished?Although an agreement was reached to reduce oil production in light of demand destruction caused by the coronavirus pandemic, oil markets appear to remain oversupplied.  Will OPEC+ and other nations agree to another deal to further reduce production?  Will U.S. production decline faster than anticipated due to low oil prices?  Will the Texas Railroad Commission implement proration orders for Texas producers?  All we can say is, stay tuned – and expect the unexpected.

When I was given the assignment to author this blog post this week, I thought "Could one possibly 'draw' a more timely assignment?" Several weeks ago, Mercer Capital’s Energy Team noted that we should consider the current condition of the oilfield services ("OFS") industry as the topic of one of our upcoming blog posts. The price for West Texas Intermediate ("WTI") had been declining since mid-February, due largely to decreased demand related to the coronavirus, and the Russia-Saudi Arabia failure to reach an agreement on production cuts. Industry participants were growing a least somewhat concerned – and then came the March 6 news that the Russian-Saudi negotiating difficulties might lead to an actual price war – and then came the March 9 actual start of the price war.More Possible OFS Bankruptcies? How Did We Get "Here"?By way of "background," the U.S. OFS industry went through a major round of bankruptcies following the late 2014 drop in oil prices. From the WTI peak in June 2014 at $106/bbl, prices fell to $58/bbl in mid-December 2014 and on to $30/bbl in January 2016. While there were a couple of upward moves in WTI in April and August of 2015, those were short-lived with the "trend" remaining a fairly clear path downward. Data provided in Haynes and Boone, LLP’s Oilfield Services Bankruptcy Tracker report (January 2020) show the annual number of identified OFS bankruptcies rising from 33 in 2015, to 72 in 2016, before easing to 55 in 2017 and 12 in 2018.  Although the WTI price was generally rising during 2016, the price remained below $55/bbl with the impact of the fall from $60+/bbl pricing continuing to ripple through the industry well into 2017. During 2018 – through October – WTI had generally ranged between $61 and $74/bbl.  OFS bankruptcies slowed, but the industry was hardly prospering. Many industry participants were more accurately described as "hanging-on" or "maintaining operations" – hoping for a rise in demand, or a drop in supply, to lift prices and move the industry to more favorable profitability.  However, in November 2018, rising worldwide inventories caused by global supply running well ahead of demand, fueled in part by the continuing growth in U.S. production, resulted in prices dipping to a low point of $43/bbl in December. While pricing improved somewhat in 2019, with WTI generally between $54 and $64/bbl, the loss of $62+/bbl pricing led to an uptick in the number of OFS bankruptcies late in 2019. Source: Haynes and Boone, LLP Recent Events – Industry and Non-IndustryAs we entered 2020, there didn’t seem to be any specific indications of change ahead for oil prices. Few had ever heard the term coronavirus and no one was anticipating a Russian break from OPEC+, or using the term "price war" in regard to the Russian-Saudi failure to reach an agreement on OPEC+ production cuts. The World Health Organization’s China office had begun receiving reports in December of an unknown virus that had led to cases of pneumonia in Wuhan, a major city in eastern China, but the term "outbreak" wasn’t being used.Within eight weeks that had all changed markedly.  By late February we had already gone beyond "outbreak" and had moved on to regularly hearing of the possibility of a pandemic.  People and countries began to react. Multiple countries were significantly limiting travel in order to slow the spread of what we all now know as the novel coronavirus, or Covid-19. Quarantines, self-imposed and government-imposed, were reducing economic production and travel, thereby reducing the level of demand for transportation fuels and fuels as a means of production. In addition, it was becoming clear that the Russian-Saudi disagreement on production cuts was more than a minor matter. The possibility of a split in the Russian-Saudi production alliance to maintain oil prices was being actively discussed as having real potential. Oil prices naturally responded with a downward turn, reaching as low as $45/bbl near the end of February.On Friday, March 6th, it was reported that Moscow had outright refused to reduce its crude production in order to offset the fall in demand related to the coronavirus.  Over the subsequent weekend, rumors swirled as to the magnitude of the impasse. Then, on Monday, March 9th, the worst possible scenario for oil prices became more than a possibility. An actual price war was initiated as both Russia and Saudi Arabia announced production increases.  The anticipated glut immediately pitched prices into a dive with the WTI falling from $41/bbl to $31/bbl by day’s end for a single-day decline of 24%.What to ExpectAs to what we can expect going forward from here, we don't know. The coronavirus, now a pandemic, is obviously spreading. How much and how far are the unknowns, along with how large the impact will be on the U.S. and global economy, and thus, the demand for oil. What is know is that oil demand will be down for a time.  What’s also known is that the outbreak will eventually be contained and the economic impact reversed when things return to "normal."So, What About Oil Supply?Well, we have two very significant oil exporters, formerly allied on oil production levels, now markedly un-allied on oil production. Not only un-allied, but both purposefully increasing production levels, in the face of lower demand, for the purpose of causing economic pain to each other. Unfortunately, that economic pain radiates, by extension, to all oil producers and the businesses that provide equipment and services to the oil producers. What does that mean for U.S. OFS market participants in the near term? Pain. Economic pain. For those that have more economic "wriggle-room," better margins, lower financial leverage, more defendable market position, it won’t be good. For those with less of that economic wriggle-room, it could go well beyond "not good." If the alliance break isn’t remedied fairly quickly and the two belligerents remain belligerent, the production glut could last long enough that a new round of OFS bankruptcies could be in the making.What’s absolutely certain is the uncertainty of it all – and at least some very real OFS industry economic pain if either the virus impact, or possibly the Russian-Saudi dust-up, lasts long enough to keep oil prices down at the new current level, or an even worse scenario, lower than the current level.

Understanding the value of an oilfield services (OFS) company is by its very nature a complex matter.  As participants in the greater energy industry, situated between the exploration and production (E&P) companies and midstream companies, the OFS sub-sector is quite broad.  It includes, businesses that have the commonality of their connection to oil and gas prices, but also the significant differences between service providers and equipment manufacturers. It also includes businesses that focus on technology advantages and those that focus on relationships, those that specialize in narrow service/product niches and those that provide a broad range of services/products.  Not to mention the differences in the economics that drive OFS companies with a focus on existing production, as opposed to those that focus on exploration. Also, the differences between those that focus on services that are particular to conventional oil versus unconventional oil, oil versus gas, shale versus tight sands.Having a firm grasp on the many similarities and distinctions is crucial in performing valuations of these businesses.  That understanding plays into the choice of which valuation approaches and methods are to be applied, and which of those approaches and methods are more reliable, or less reliable, depending on the subject company’s positioning and where the industry is in it’s potentially wide ranging cycles.As part of any OFS company appraisal, one must consider expectations for both shorter-term and longer-term operating results.  Industry cyclicality creates challenges in evaluating expectations that can lead to material over-valuations, or under-valuations, unless one has the depth of experience and industry understanding to navigate the many considerations that impact OFS companies.In our latest whitepaper, Understanding Oilfield Services Companies & How to Value Them, we provide invaluable guidance in regard to these aspects of the OFS industry. Click below to download whitepaper.>>Download Whitepaper

Understanding the value of an oilfield services (OFS) company is by its very nature a complex matter. The unpredictable cyclicality of the oilfield services industry requires careful consideration of many industry-wide and company-specific factors in developing a reasonable forecast of future operating results. While consideration of such factors should be part of the analysis in the appraisal of businesses in all industries, the impact of these considerations is magnified in highly cyclical industries such as that served by OFS businesses.This whitepaper provides invaluable guidance in regard to these aspects of the OFS industry.

When performing a purchase price allocation for an oilfield services company, careful attention must be given to both the relevant accounting rules and the specific nuances of the oil and gas industry. Oilfield services companies can entail many unique characteristics that are not present in non-oilfield related businesses such as manufacturing, wholesale, non-energy related services, or retail.  Our senior professionals bring significant experience in performing purchase price allocations in the oilfield services area where knowledge of these characteristics is crucial to determining the proper allocation among the subject company’s assets.For the most part, current assets and current liabilities are relatively straight forward. The unique factors of an oilfield services company are found in the fixed assets and intangibles: specialized drilling and production equipment, service contracts, proprietary technology (patented, or unpatented), methods, or software, in-process research and development assets (IPR&D), etc.  In addition, the proper consideration of contributory asset charges in the appraisal of existing customer relationships or technology in the context of oilfield services companies requires a thorough understanding of how such contributory assets are utilized in generating the subject company’s expected operating results.  We will explore the unique factors in future entries. In this blog post, we discuss the guidelines for purchase price allocations that all companies must adhere.The unique factors of an oilfield services company are found in the fixed assets and intangibles.Reviewing a purchase price allocation report can be a daunting task if you don’t do it for a living – especially if you aren’t familiar with the rules and standards governing the allocation process and the valuation methods used to determine the fair value of intangible assets. While it can be tempting as a financial manager to leave this job to your auditor and valuation specialist, it is important to stay on top of the allocation process. Too often, managers find themselves struggling to answer eleventh-hour questions from auditors or being surprised by the effect on earnings from intangible asset amortization. This guide is intended to make the report review process easier while helping to avoid these unnecessary hassles.It should be noted that a review of the valuation methods and fair value accounting standards is beyond the scope of this guide. Grappling with these issues is the responsibility of the valuation specialist, and a purchase price allocation report should explain the valuation issues relevant to your particular acquisition. Instead, this guide focuses on providing an overview of the structure and content of a properly prepared purchase price allocation report.General GuidanceWhile every acquisition will present different circumstances that will impact the purchase price allocation process, there are a few general rules common to all properly prepared reports. From a qualitative standpoint, a purchase price allocation report should satisfy three conditions:The report should be well-documented. As a general rule, the reviewer of the purchase price allocation should be able to follow the allocation process step-by-step. Supporting documentation used by the valuation specialist in the determination of value should be clearly listed and the report narrative should be sufficiently detailed so that the methods used in the allocation can be understood.The report should demonstrate that the valuation specialist is knowledgeable of all relevant facts and circumstances pertaining to the acquisition. If a valuation specialist is not aware of pertinent facts related to the company or transaction, he or she will be unable to provide a reasonable purchase price allocation. If the report does not demonstrate this knowledge, the reviewer of the report will be unable to rely on the allocation.The report should make sense. A purchase price allocation report will not make sense if it describes an unsound valuation process or if it describes a reasonable valuation process in an abbreviated, ambiguous, or dense manner. Rather, the report should be written in clear language and reflect the economic reality of the acquisition (within the bounds of fair value accounting rules). This can be particularly daunting if the reviewer of the purchase price allocation report does not have significant experience in working with oilfield services industry participants.  The oilfield services industry is particularly strong in industry-specific terminology and jargon that can lead to a lack of understanding among purchase price allocation report reviewers that lack a deep industry background.Definition of AssignmentA purchase price allocation report should include a clear definition of the valuation assignment. For a purchase price allocation, the assignment definition should include:The definition of the valuation objective should specify the client, the acquired business, and the intangible assets to be valued.The purpose explains why the valuation specialist was retained. Typically, a purchase price allocation is completed to comply with GAAP financial reporting rules.Effective Date. The effective date of the purchase price allocation is typically the closing date of the acquisition.Standard of Value. The standard of value specifies the definition of value used in the purchase price allocation. If the valuation is being conducted for financial reporting purposes, the standard of value will generally be fair value as defined in ASC 820.Statement of Scope and Limitations. Most valuation standards of practice require such statements that clearly delineate the information relied upon and specify what the valuation does and does not purport to do.Background InformationThe purchase price allocation report should demonstrate that the valuation specialist has a thorough understanding of the acquired business, the intangible assets to be valued, the company’s historical financial performance, and the transaction giving rise to the purchase price allocation.Understanding of the BusinessThe purchase price allocation report should include a discussion related to the acquired company which demonstrates that the valuation specialist is knowledgeable of the company and has conducted sufficient due diligence for the valuation. The overview should also discuss any characteristics of the company that plays a material role in the valuation process. The description should almost always include discussion related to the history and structure of the company, the competitive environment, and key operational considerations.In the case of acquisitions within the oilfield services industry, the pertinent facts include a thorough understanding as to the demand for the subject company’s services across the various basins within the target market.  Unlike many other industries, oilfield services businesses may provide services that are specific to certain basins.  Therefore, expectations regarding the specific basins served may be of much greater importance than expectations for the overall oil and gas industry.Intangible AssetsThe discussion of the subject intangible assets should both provide an overview of all relevant technical guidance related to the particular asset and detail the characteristics of the assets that are significant to the valuation. The overview of guidance demonstrates the specialist is aware of all the relevant standards and acceptable valuation methods for a given asset.Upon reading this section, the reviewer of the purchase price allocation report should have a clear understanding of how the existence of the various intangible assets contribute to the value of the enterprise (how they impact cash flow, risk, and growth).Within the oilfield services industry, in particular, one may have to spend a significant amount of time in the determination of what intangible assets were acquired, what intangible assets should recognized as a separate asset from goodwill (based on the legal/contractual rights and separability considerations) and what intangible assets are likely to have a material value.  These can differ markedly across industries and such considerations can be somewhat unique in the oilfield services industry.Past PerformanceThe historical financial performance of the acquired company provides important context to the story of what the purchasing company plans to do with its new acquisition. While prospective cash flows are most relevant to the actual valuation of intangible assets, the acquired company’s historical performance is a useful tool to substantiate the reasonableness of stated expectations for future financial performance.The historical financial performance of the acquired company provides important context to the story.This does not mean that a company that has never historically made money cannot reasonably be expected to operate profitably in the future. It does mean that management must have a compelling growth or turn-around story (which the specialist would thoroughly explain in the company overview discussion in the report).Understanding an oilfield services company’s past financial performance requires knowledge of industry-specific trends that can impact activity levels, pricing for particular services, competing service providers, and profit margins.  The oilfield services industry is subject to potentially wide fluctuations in activity that can be driven by commodity prices and technological changes.  A thorough understanding of these dynamics is necessary in order to correctly interpret past performance among industry participants.Transaction OverviewTransaction structures can be complicated and specific deal terms often have a significant impact on value. Purchase agreements may specify various terms for initial purchase consideration, include or exclude specific assets and liabilities, specify various structures of earn-out consideration, contain embedded contractual obligations, or contain other unique terms. The valuation specialist must demonstrate a thorough understanding of the deal terms and discuss the specific terms that carry significant value implications.Determination of ValueThe purchase price allocation report should provide an adequate description of the valuation approaches and methods relevant to the project. In general, the report should outline the three approaches to valuation (the cost approach, the market approach, and the income approach), regardless of the approaches selected for use in the valuation. This demonstrates that the valuation specialist is aware of and considered each of the approaches in the ultimate selection of valuation methods appropriate for the given circumstances.Any of a number of valuation methods could be appropriate for a given intangible asset depending on the specific situation. While selection of the appropriate method is the responsibility of the valuation specialist, the reasoning should be documented in the report in such a way that a report reviewer can assess the valuation specialist’s judgment.In the closing discussion related to the valuation process, the report should provide some explanation of the overall reasonableness of the allocation. This part of the purchase price allocation report should include both a qualitative assessment and quantitative analysis for support. While this support will differ depending on circumstances, the report should adequately present how the valuation “hangs together.”Within the oilfield services industry determination as to the reasonableness of the indicated allocation of value (purchase price) is often a factor of whether the subject company’s services are subject to proprietary technology, the level of fixed assets required to provide the subject company’s services and the level of personal interaction with customers.  Based on such factors, the allocation of value might be reasonably expected to be skewed to particular types of assets, with higher, or lower, expected levels of goodwill.Keep in Mind, it’s Not a BlackboxA purchase price allocation is not intended to be a black box that is fed numbers and spits out an allocation. The fair value accounting rules and valuation guidance require that it be a reliable and auditable process so that users of financial statements can have a clear understanding of the actual economics of a particular acquisition. As a result, the allocation process should be sufficiently transparent that you are able to understand it without excessive effort, and the narrative of the report is a necessary component of this transparency.

In a prior blog post, we provided an overview of the saltwater disposal (SWD) industry, detailing the source of demand for SWD services, the impact of the shale boom, geographic distribution, site selection, construction, and regulation.  We now take a look at the economics of the SWD industry and the trends that impact the economics.SWD EconomicsIn the past, SWD wells were typically drilled and operated by producers for the purpose of handling the producers’ own disposal needs.  However, the growing inefficiency of individual operators having in-sourced SWD operations has in recent years created an increased demand for specialized outsourced SWD services.  The expertise and economies of scale provided by these independent SWD service providers allow for reductions in the saltwater transportation and disposal expense to the producer.  As a result, the operation of SWD facilities as a stand-alone business has shown enormous growth in recent years.Revenue StreamsRevenues streams to SWD operators consist primarily of disposal fees – typically in the range of $0.50 to $2.50 per barrel – and skim oil sales.  Produced water contains significant amounts of suspended crude oil that the SWD facility “skims-off” (by various methods) and sells to increase revenues.  Where disposal services are abundant, the cost is typically in the lower third of the indicated range.  Locations with fewer available SWD facilities can see fees in the upper end of the range.  Skim oil volumes are typically quite small relative the volume of produced water received for disposal.  However, the sale of the skimmed oil can account for 10% to 30% of total SWD revenues.  The portion of revenues attributable to skim oil sales depends on the SWD facility’s skimming and impurity removal capabilities, in addition to the presence of a local market for alternative skim oil use.Revenues streams to SWD operators consist primarily of disposal fees – typically in the range of $0.50 to $2.50 per barrel – and skim oil sales.Additional revenues may be generated by providing trucking services for the purpose of transporting the produced water from the well site to the disposal facility.  Revenues from such services can vary widely.  Transport rates are typically near $1 per barrel per hour of transport time.  Where SWD facilities are readily available and the distance from the well site is minimal, the trucking cost may only add $0.50 per barrel.  However, the incremental revenue can reach $4 to $6 per barrel where facilities are lacking and the distance is significant.As with the in-sourcing of SWD operations by producers, the provision of trucking services by SWD facility operators is on the decline.  As the oilfield waste disposal industry has rapidly grown in recent years, the ability to provide specialized services at significant economies of scale has led to oilfield waste transportation services being provided as a stand-alone business.  As detailed below, the growing benefits of transporting produced water to SWDs via pipeline has also contributed to the decline in trucking services among SWD facility operators.Cost StructureThe structure of a SWD facility’s expenses is significantly skewed to fixed costs relative to variable costs.  Like other fixed asset-intensive businesses, a large portion of a SWD facility operator’s costs are incurred up-front in the construction of the facility, including the cost of drilling the primary disposal well and any back-up well.  While drilling costs can vary markedly based on the site geology, the target zone, and well depth, the total facility cost can easily reach $3 million to $4 million even if the facility offers no produced water transportation via pipeline.Ongoing expenses are fairly limited and are primarily comprised of power and maintenance/repair costs.  Incremental costs are typically quite low, often less than $1 per barrel.  Labor costs vary little whether disposal volumes are high or low.  Ticketing and invoicing processes are typically heavily automated, and therefore, related expenses do not vary significantly with volumes.The one area of expense that is to some degree within the control of the SWD operator is maintenance expenses.  The SWD operator is well advised to exercise diligence in the maintenance of the SWD well as any downtime, expected or unexpected, can be costly in terms of lost revenues.Focus on VolumeGiven the fixed-heavy cost structure, the SWD facility operator’s primary lever for improving operating results lies in increasing volumes.  However, for the well operator, the primary consideration in choosing a SWD facility is the transportation cost, which is largely a factor of the distance from the well site to the disposal facility.  So, once the SWD facility is sited, the primary SWD decision driver – distance – is fixed and can’t be altered.   To gain more disposal business, SWD facilities often provide transport services via truck.  However, as previously indicated, recent trends have moved SWD facility operators away from trucking services.Trends in Volume AcquisitionHistorically, the transportation of produced water to a commercial disposal facility has been heavily weighted toward trucking.  Due to the smaller volumes of water requiring disposal and the typical patchwork of acreage controlled by any single E&P company, the construction and use of pipeline systems for gathering and transporting produced water to a central disposal facility was cost-prohibitive.  However, with the vast increase in produced water volumes in recent years, and the recent trend among the E&Ps to aggregate more contiguous acreage, the feasibility of pipeline systems has grown.  With trucking costs now more than doubling pipeline transportation costs in many markets, the large up-front cost of constructing a pipeline network is often no longer an economic hindrance.Similarly, several producers have put in place longer-term programs for the systematic development of their large – and more contiguous - acreage holdings.  As part of these programs, the producers have found it economically viable to build out pipeline systems for gathering and transporting produced water to local SWD networks.  Although the trucking of produced water is still dominant in some areas - the Bakken and the Eagle Ford - SWD operators in the Delaware Basin have indicated that piped volumes are likely exceeding trucked volumes in that pipe-heavy area.  Data from NGL Energy shows the progression of piped versus trucked produced water in recent years. While many of the more extensive pipeline systems were originally operated by the E&Ps, much of the current systems are held by businesses that specialize in oilfield waste disposal via E&P asset drop-down and asset sale transactions. Produced Water ContractsAlong with the rise in the prevalence of produced water pipeline gathering and transport systems has come the need for the owners/operators of those systems to ensure the disposal volumes into their systems will be sufficient to service the debt taken on related to the pipeline construction or acquisition.  In pursuit of steadily produced water volumes, SWD operators and E&Ps have begun entering into contractual commitments that often include dedicated acreage and/or take-or-pay volumes.  These contractual relationships are often multi-year agreements, ensuring a steady stream of produced water.  The enhanced economies of scale result in a risk/return profile that is less like that of oilfield service providers and more like midstream companies.  This lowers the cost of capital for SWD operators.Produced Water RecyclingOne detrimental economic trend in the SWD industry is produced water recycling.One detrimental economic trend in the SWD industry is produced water recycling.  Hydraulic fracturing requires enormous amounts of water and therefore results in enormous amounts of produced water.  Traditionally, fracking operations only utilized freshwater.  However, in recent years operators have begun experimenting with mixes of fresh and produced water for fracking purposes with largely favorable results.  This brings the potential for significant quantities of produced water no longer heading to SWD facilities for disposal but instead being recycled and reused at the well site.  While reducing both freshwater supply and produced water disposal expenses would seem to be an obvious benefit to the operator, produced water recycling carries its own cost.Produced water recycling entails a multiple-step process with each step removing a certain part of the produced water mix.  Although the recycling process does not have to bring the produced water to a “drinking water” level of freshness, recycling to the level required for use in fracking can entail a significant expense.  The recycling economics often hinges on the availability – and therefore cost – of freshwater for fracking use.  In areas where freshwater is abundant and inexpensive, recycling economics are less beneficial.  In areas where freshwater is scarce and expensive, recycling often makes economic sense.  As recycling technology improves and greater efficiencies are realized, it’s likely that a greater percentage of produced water will be reused, rather than removed for disposal. However, research by Raymond James indicates that fracking-related water demand growth falls far short of estimates of produced water disposal demand growth, even with produced water recycling considerations.[caption id="attachment_27673" align="aligncenter" width="940"]Source: EIA, Drilling Info, Baker Huges, Raymond James Research[/caption] As of now, recycling of produced water is still in early development with estimates of disposal to recycle ratios at 20:1. SummaryAs detailed, the outlook of the SWD industry is quite favorable although the economics are, and will continue to be, in a state of flux as the industry grows and matures.  Despite some potential detrimental market dynamics along the way, the overall direction points to strong benefits to investors as the business of SWD continues to evolve away from a being cost center for operators, to a cash flow generating third-party service provider to operators.

The appraisal of businesses involved in the refining of crude oil entails a number of challenges.  Some are unique to the industry, and others are more common.  The challenges arise primarily in two areas – assessing the level of uncertainty inherent in the entity’s future cash flows and forecasting the entity’s future operating results.The greater the range of future cash flows, the greater the rate of return an investor will require to invest in the business.Assessing the level of uncertainty for a particular business’ future cash flows is a key part of any business valuation.  Basic economics tells us that the present value of an expected future cash flow is greater if the possible range of the cash flow is +/-10% from the expected level, compared to the possible range of the cash flow being +/-30% from the expected level.  Investors aren’t willing to pay as much for an expected future cash flow with a potentially high divergence from expectations than for an expected future cash flow with a potentially low divergence from expectations.  The greater the range of future cash flows (the degree of uncertainty of the future cash flows), the greater the rate of return an investor will require to invest in the business.In addition to the challenges posed in the risk (uncertainty) assessment, the appraisal of an oil refinery business also carries particular challenges in forecasting future operating results.  Oil refining entails not only a commodity input (feedstock), but also commodity products - gasoline, diesel, liquefied petroleum gases, jet fuel, residual fuel oils, still gases, lubricants, and waxes.  Complexity increases in these product markets since they are significantly influenced by international, domestic and local supply and demand, heavy regulation, domestic politics and international politics.  Add to those enormous capital requirements and high barriers to entry and you have an industry rife with forecasting complexity.Assessing UncertaintyAssessing the level of cash flow uncertainty for a particular crude oil refining business requires a thorough analysis of the subject company’s internal operations. This analysis includes its facilities, suppliers, customers, level of integration, and use of hedging.  Additionally, external factors, such as infrastructure availability and limitations, feedstock and product supply and demand, government and environmental policies, geopolitical matters, and currency exchange rates must be considered.  Some potentially key uncertainty assessment considerations are addressed as follows:ConfigurationConfiguration refers to a facility’s ability to accept a range of crude oils (light-sweet crude, or heavy crude) as feedstock.  Refineries with limited feedstock abilities lack the flexibility of shifting from one type feedstock oil to another, thereby exposing the business to uncertainties regarding particular feedstock supply and demand.  For example, refineries that were specifically designed (configured) to process heavy crude would be exposed to the negative economics of an unexpected decrease in heavy crude availability. On the contrary, refineries configured for greater feedstock flexibility would potentially avoid the negative impact of a reduced supply of heavy crude by shifting to a light crude feedstock.Secondary Processing SystemsSecondary processing capabilities refers to the ability to engage in processing crude oil beyond initial distillation to processes involving catalytic cracking and reforming.  These secondary processes allow a refinery to shift between maximizing distillate production in the winter months when heating oil is in higher demand and gasoline production during the summer months when automotive fuel is in demand.  Without secondary processing systems, a refinery is more vulnerable to the negative economics of seasonal product supply and demand shifts.Feedstock Source ConstraintsFeedstock source constraints refer to the refinery’s ability to economically choose between feedstock sources.  Facilities that are located along the U.S. coastline have the option of using either the WTI (inland U.S. produced) or the Brent (North Sea produced) varieties of crude oil.  As such, they have the ability to favorably respond to shifts in WTI versus Brent pricing (the Brent-WTI spread).  Refineries located in the U.S. interior have a much lower economic ability to utilize Brent and are therefore subject to the impacts (positive or negative) of pricing variations between the two varieties.Inventory ExposureRefineries typically hold significant levels of inventory (feedstock and product inventory) with these inventories comprising 13% to 17% of total assets.  Due to the potential for material swings in the market price for the feedstock inventories (crude oil) and end products, refiners face a significant level of uncertainty regarding their profits.   Market-driven increases/decreases in crude prices can raise/reduce the value of feedstock holdings, while market-driven increases/decreases in end product prices can raise/lower revenues and profit margins.  While protection against the negative impacts of such market changes is available through commodity price hedging, refining businesses vary in the degree to which they utilize hedging strategies.  In appraising a particular oil refining business, the appraiser must gain a clear understanding as to the commodity price risks that are hedged and those that remain unhedged.Ability to Pass-on CostsThe ability to pass-on the higher feedstock costs is often dependent on the current conditions in the local and international end product markets.When crude oil prices are rising, oil refinery businesses may be able to pass those higher feedstock prices on to customers in the form of higher-end product prices and thereby maintain margins.  The ability to pass-on the higher feedstock costs is often dependent on the current conditions in the local and international end product markets.  If the petroleum product market is experiencing particularly high supply, or low demand, the refiner’s ability to pass-on higher crude oil prices may be significantly limited.  However, in situations of lower supply, or higher demand, higher crude prices may more readily be passed through to customers.  As such, an appraiser must not only be aware of near-term expectations for crude prices, but also near-term expectations for the various end products of the particular refining business in order to correctly assess the level of uncertainty that should be factored into the appraisal analysis.  In performing this part of the analysis, the appraiser must take into consideration the degree to which the uncertainty would be expected to be avoided by the subject company’s use of hedging.IntegrationSome oil refiners are integrated in that they are also involved in the ownership/control of crude oil reserves, or as with many larger refineries, they also own the petrochemical plant customer of the refiner.  Such integrated refineries can allow for the shifting commodity price risks between the refinery and the entity that owns the crude reserves or the petrochemical producer.  As such, an important part of the refinery appraisal involves a careful assessment of how the commodity price risk is being handled between the entities involved, and how such handling of the risk should be incorporated into the appraiser’s assessment of future cash flow uncertainty.Infrastructure ChangesInfrastructure changes can have a significant impact on a refinery’s profitability. Changes in the availability of the necessary infrastructure for bringing crude oil “to market” (to local refineries, more distant refineries, or to a port for export) can have a significant impact on the refinery’s profitability.  For example, for years various market forces (high international demand for Brent, high WTI supply and interior U.S. pipeline capacity deficiencies) maintained a Brent-WTI spread that was advantageous to U.S. refineries.  However, more recently shifts in market forces, including improvement of U.S. pipeline capacity, has contributed to a significant narrowing of the Brent-WTI spread. These shifts have resulted in the loss of a considerable portion of the crude supply cost advantage for U.S. refineries.  A particular refinery’s exposure to potential changes in crude transportation infrastructure must be considered by an appraiser as part of the analysis in determining the relative uncertainty of the refinery’s cash flows.Facility EfficiencyThe efficiency of a particular refinery can be a material contributor to cash flow uncertainty.  The oil refining industry is subject to a large number of market forces that can have a material impact on profitability.  In considering the refinery’s ability to successfully adjust to changes in those many market forces, one must consider the facility’s efficiency.  In an environment where the number of facilities is expected to downsize and consolidate in the short-term, facilities with lower levels of efficiency are more subject to having their utilization trimmed back, or even being shut-down.Government RegulationThe oil refining industry is subject to an extensive array of both federal and state regulations, which can be changed, delayed, or accelerated, depending on the political climate. While some of these regulations are static, others have restrictions that are implemented over time.  For example, MarPol 2020 represents a significant, albeit long foreseen, change beginning January 1, 2020 where the allowable sulfur for fuel used in ocean-bound vessels is reduced from 3.5% to just 0.5%.  U.S. refiners with the ability to produce a higher proportion of lighter, low-sulfur fuels from each barrel of oil will stand to profit from the change in legislation, particularly if supply is low in the short term following the change.One must be aware of potential regulatory changes and the facility’s ability to conform.In the appraisal of a refining business, one must be aware of potential future regulatory changes and the particular facility’s ability to conform to such regulations.  In some cases, this flexibility may be tied to the configuration of the plant, and in others may be tied to technology-related efficiency.  Any factors that create a question as to the ability or willingness from a financial perspective to comply with potential regulatory changes must be considered in assessing the uncertainty of future cash flows.Forecasting Operating ResultsForecasting future operating results can present a challenge for many industries. With the number of market forces in play, several considerations in the forecasting process deserve special attention when appraising a business in the oil refining industry.  Some of the areas for particular attention include commodity pricing considerations on volumes and margins, and capital intensity considerations.Commodity Pricing ConsiderationsThe commodity nature of refinery feedstock (crude oil) makes the forecasting of future revenues worthy of particular attention.  International, domestic and local supply and demand, heavy regulation, domestic politics and international politics all come into play in the oil refining industry and the uncertainty as to the impact of these various factors is why hedging plays such a significant role within the industry.  While careful analysis can identify pertinent short-term and long-term trends, the future direction of feedstock prices always remains uncertain to some degree.  As such, the appraiser of a refinery business must be familiar with the mix of factors that can impact future feedstock prices and accurately factor the “knowns” and “unknowns” into projections of future revenue levels.The factors that come into play in forecasting future refinery revenues can also impact future operating margins, but not necessarily.  As previously mentioned, the ability to pass-on changes in feedstock prices can vary over time based on supply and demand dynamics regarding the refinery’s products.  Similar to the refinery’s crude oil feedstock, the end products are also commodities and are therefore subject to pricing changes that are well beyond the control of the refinery operator.  In some cases, those dynamics may allow for changes in crude oil prices to be passed on to the refinery’s customers, thereby maintaining operating margins.  However, end product market dynamics may create an environment where increases in crude oil prices can’t be passed-on such that future operating margins would be expected to be trimmed.Capital IntensityCapital expenditures in the oil refining business can be much more significant and much less steady in magnitude than in other industries.Petroleum refining is a capital intensive process requiring large investments in property, plant, and equipment (PP&E).  While machinery and equipment maintenance expenses are often somewhat steady over time, certain aspects of such expenses can be much more irregular.  In contrast, capital expenditures in the oil refining business can be much more significant and much less steady in magnitude than in other industries.  Short-term capital expenditures expectations can vary widely depending on past maintenance expenditures and the facility’s past acceleration, or delaying, of major expenditures.  Longer-term capital expenditures, or periodic expenditures, are typically significant and quite large.  A detailed discussion with facility management is often necessary in order to gain a clear understanding as to both timing and cost expectations for such expenditures.  With the high level of industry regulation, often environmentally focused, the timing and magnitude of some capital expenditures may well be outside of facility management control.In addition to the more direct impact of oil refinery capital intensity on maintenance and capital expenditures is the impact on tax expenditures from the depreciation of the machinery and equipment.    With PP&E assets totaling hundreds of millions, or even billions of dollars, tax depreciation of those assets can have a significant impact on expected cash flows.  The difference of results between a simplified straight-line depreciation modeling and a more detailed accelerated (MACRS) tax depreciation modeling can be significant even before incorporating potential bonus depreciation and Section 179 immediate expensing of qualifying property.While appraisers may be provided with detailed tax depreciation schedules for existing machinery and equipment, it may be within the appraiser’s scope of service to develop the expected tax depreciation scheduling for machinery and equipment that will be put in place during the forecast period.  The detailed tax depreciation forecasting may not be particularly pertinent in less asset-intensive industries, but it can have a material impact in the appraisal of more asset-intensive businesses such as oil refining.Mercer Capital has a breadth and depth of experience in the appraisal of businesses in the oil and gas industry that is rare among independent business appraisal firms.  Our Energy Team is led by professionals with 20 to 30+ years of experience involving upstream businesses (E&Ps, oilfield product manufacturers and oilfield service providers), midstream (gathering systems, pipeline MLPs, pipeline processing facilities), and downstream (refining, processing, and distribution).   Feel free to contact us to discuss your valuation needs in confidence.

In our prior two Energy Valuation Insights blog posts, we detailed the specifics of “what is” and “what are the characteristics of” an oilfield equipment/services company (“OFS”), and detailed the typical approaches and methodologies utilized in valuing OFS companies.  This week, we’ll address some of the special considerations that must be given attention in the appraisal of OFS companies.  Specifically, the challenges in forecasting the future operating results for an OFS company.In the appraisal of an OFS company, the application of the income approach often includes the application of a discount cash flow (“DCF”) methodology.  Actually, one might make the argument that the application of the income approach in appraising an OFS company should nearly always include the application of a DCF methodology, as opposed to relying solely on a capitalization of earnings methodology (“capitalization method”).  While application of a capitalization method can provide a reasonable indication of value for companies in many industries, doing so for an OFS company can be problematic due to the inherent cyclicality of the OFS industry.  One can attempt adjustments to a capitalization method indication of value to account for future deviations in cash flow growth rates (such as those caused by OFS industry cyclicality), but doing so can involve unnecessary subjectivity, resulting in an indication of value that may lack reliability.  Typically, the better, and often more reliable, option is to utilize a DCF method using a forecast of future operating results rather than a capitalization method with imprecise adjustments.Understanding Industry Cyclicality is an Important Factor in Valuing an OFS CompanyIn applying the DCF method, the starting point is, of course, the development of a forecast of future cash flow for the subject company, which typically begins with a forecast of future revenues.  Here we run into the first of several challenges in the appraisal of OFS companies.  The OFS industry is of the most cyclical of industries that analysts can cover.  Not just cyclical with the general economy of the region, nation or world, but cyclical in a way that is much more difficult to predict fluctuations in the price of oil (or natural gas) tied to a whole host of factors including technological, political, and even geopolitical factors can make forecasting complicated very quickly.Several varying forces can make predicting the future demand for oil from a particular region, and therefore, the demand for OFS products/services, quite difficult.Demand for oil and gas, and therefore demand for OFS products/services, can be as simple as the fact that in a robust economy more goods are being bought by end users and consumers.  More purchases of goods, means more goods have to be transported to the end user/consumer, which requires more fuel to facilitate that transportation.  Technology can impact the supply side of the equation as oilfield technology advances can lower the cost of oil production, thereby encouraging greater production even when oil prices are stable, or possibly even in decline, all else being equal.  Local and national politics can impact demand as well.  In the U.S., recent differences in positions on the use of coal as a power source have inserted a new dynamic into the economic demand for oil.  In the geopolitical realm, bans on the importation of oil from certain countries (Iran or Venezuela, for example) have created shifts in demand for oil from other oil-producing countries.These varying forces can make predicting the future demand for oil from a particular region, and therefore, the demand for OFS products/services in that region, quite difficult.  As indicated in the chart below, the timing and magnitude of cycles in the OFS industry can vary significantly.[caption id="attachment_26698" align="alignnone" width="812"]Note: Median year-over-year revenue change among the smaller publicly-traded OFS industry participants.[/caption] Forecasting OFS Company RevenuesIn forecasting OFS company revenues, one must distinguish between the short-term forecast and the long-term forecast.   The short-term forecast will be primarily focused on the current direction of industry revenues, the typical length of industry cycles in estimating the timing of a current down-cycle bottom (or current up-cycle peak), and expectations for the subject company’s revenue cycle relative to that of the OFS industry as a whole (lagging or leading).  The long-term forecast for the subject company will be more focused on the expected timing of a return to the mid-cycle level of revenues and the subject company’s particular expected mid-cycle level of revenue, with a potential adjustment for possible changes in the subject company’s market share.In performing the company level analysis, it’s always important to be aware of past transaction activity, changes in product/service, mix, or changes in markets served.In support of both the short-term and long-term forecasting considerations, an analysis of past OFS industry cycles and of the subject company’s past revenue cycles is warranted.  With access to certain specialized databases, a detailed analysis of industry cycles (or industry participant cycles) can be readily performed.  The same cycle analysis regarding the subject company is possible if the company has a long-enough operating history.  In performing the company level analysis, it’s always important to be aware of past transaction activity (acquisitions, or divestitures), changes in product/service, mix, or changes in markets served, that might influence the results.Based on these analyses, the appraiser must determine reasonable estimates for the following:The time until the then current up-cycle will peak, or current down-cycle will bottomThe revenue level at the current up-cycle peak, or current down-cycle bottomThe time to reaching the next mid-cycle point, or mid-cycle level of revenue Estimates based on a sound analysis of historical industry and subject company data will result in a reasonable revenue forecast.Forecasting ConsiderationsBeyond the industry-wide considerations necessary in developing the OFS company forecast, one must also consider a number of more specific, non-industry-wide factors.  These may include the target market (geographic), the subject company’s specific product/service offerings, the mix of product/service offerings, and the subject company’s ability to weather a current industry down-cycle.Geographic Target MarketUnlike participants in many other industries, OFS industry participants expect that future operating results can be significantly impacted by the geography of their target market, or, more specifically, the geology of their target market.  The cost of extracting oil/gas can vary significantly depending on the basin being served.  Similarly, the cost of processing (refining) oil from different basins can vary significantly, based on the quality of the oil being produced.  For example, according to a 2016 EIA study, lower production costs were more prevalent in the Delaware Basin and Appalachian Basins while higher production costs were more standard in the Eagle Ford and Midland Basins1.The differences in production costs were partially a factor of the geology of the basins, which impacts the specific processes necessary in order to extract the reserves.  In the Marcellus Basin, shallow formations and pad drilling techniques allow for lower cost production, while in the Eagle Ford Basin, deeper and more technically challenging formations tended to result in higher production costs.  This changes over time with experience and technology accelerators, as the Eagle Ford’s costs have come down for several producers in the past year.Cost differentials can result in potentially significant differentials in drilling and production activities across the various basins, depending on prevailing oil prices.These cost differentials can result in potentially significant differentials in drilling and production activities across the various basins, depending on prevailing oil prices.  Proximity to refiners also plays a role as transportation costs can add up.  Prices at $60/bbl, for example, may spur activity in one basin while another basin remains at markedly lower activity levels, often captured in “break-even” prices.  As such, in estimating future operating activity levels of an OFS company, one must be aware of the expected oil prices and the level of activity that would be expected in conjunction with those prices in the basins served by the subject company.OFS companies can mitigate some of the cyclicality by diversifying across basins. Operating in multiple markets can spread costs over more operations as well. OFS companies concentrated in one particular basin, on the other hand, would likely experience more volatile swings, particularly if they operate in a high-cost basin.Specific Product/Service OfferingsThe specific products and services offered by the subject OFS company must also be considered, as some services will only experience increased demand at higher oil price points, that justify the operator incurring the additional expense.  For example, even in a period of rising production, a provider of services related to more expense stimulation techniques may not see a significant increase in the demand for its services until a certain price point is achieved.  On the other hand, providers of services that are necessary for more general production activities would be expected to experience cyclical demand for its services more in-line with the general OFS industry.  Some may even be insulated from price declines as E&P companies will continue to demand certain services regardless of price.Mix of Product/Service OfferingsSimilar to the impact of diversification of basins served, diversification across products and services offered can potentially contribute to reduced cycle extremes.  An OFS company might see greater cycle extremes for certain exploration and production services. However, offering multiple services not tied to those same exploration and production activities can provide needed diversification which may mute cycle highs and lows.Financial Condition of the Subject CompanyThe subject company’s financial condition is often given inadequate consideration in forecasting future operating results; however, it can be critical when appraising companies in industries that commonly experience more significant cycle highs and lows, such as the OFS industry.  This is particularly important when the subject industry is facing a material downturn in activity in the early portion of the forecast period.Consideration of a company's financial condition can be critical when appraising companies in industries that experience significant cycle highs and lows, such as the OFS industry.During an industry downturn, certain expenses can’t be avoided, and the subject company may generate negative cash flows until demand returns.  As such, an analysis of the company’s financial condition is important in determining its ability to weather the downturn and participate in the expected improved conditions as the industry cycle swings back to more favorable conditions.Companies that have ample cash reserves, low levels of debt, or a significant ability to reduce fixed costs will be more likely to overcome the impact of the down cycle. Companies that have little cash reserves, substantial leverage, or are less able to cut costs may have to take more significant actions to weather the downturn.  Such actions may impact the degree to which they’re able to participate in the industry’s next upswing in demand.  In forecasting future operating results, one must include an analysis of the subject company’s financial condition and consider what actions may be necessary in order for the company to deal with the short-term cash outflows.  Those actions may, if more extreme, result in the subject company participating to a lesser degree in the eventual industry recovery.Forecasting OFS Company Cash FlowNext, is the task of deriving a cash flow forecast from the revenue forecast, through the forecasting of cost of sales and operating expenses.  In both cases, a greater level of analysis is warranted for OFS industry participants than for participants in industries less subject to large cycles.  The reason being that depending on the relative level of fixed and variable expenses in cost of sales and operating expenses, those expenses, as a percentage of revenues may fluctuate significantly over the course of the industry’s cycle.  As demand for labor, materials, and products will be high near the peak of the industry cycle, their cost will potentially increase relative to revenues, resulting in higher cost of sales relative to revenue and lower gross margins.  The opposite would be expected for time periods near the bottom of the cycle, with demand at a low point and cost of sales lower relative to revenues, resulting in higher gross margins.  Operating expenses can be tied to these peaks and valleys in the industry cycle as well, but the impact may not be as severe, since they have a larger ratio of fixed versus variable components relative to the cost of sales expense.Unlike companies participating in less cyclical industries where it may be reasonable to forecast cost of sales and/or operating expenses as a static, or near static, percentage of revenues, forecasting OFS company expenses (cost of sales and operating) typically requires an analysis of past operating results in order to identify cycles and ranges of company expenses relative to revenue.  The question to be addressed is essentially, what will my cost of sales percentage (of revenues) be at the level of revenue forecasted for each discreet period in the forecast and what will my operating expense percentage be at the level of revenue forecasted for each period in the forecast?  Note that due to the likely presence of a greater fixed/variable expense ratio in operating expenses (than cost of sales), the change in operating expenses as a percentage of revenues over the forecast period will likely be more pronounced than for cost of sales.Extreme Industry Condition ImplicationsRare indeed is the industry that is subject to the potential cyclical extremes of the OFS industry.  As indicated in the chart below, in 2008 oil prices surged to unprecedented levels for several months (that haven’t been seen since) resulting in a significant spike in OFS product/service demand.  Shortly thereafter, in 2009, oil prices dropped sharply to levels that hadn’t been seen since 2003, only to be followed by a sharp increase to a level generally in-line with the price trend that had been established during the 2004 to 2007 period.[caption id="attachment_26700" align="alignnone" width="740"]Source: EIA[/caption] Due to these fluctuations in commodity prices, and therefore OFS activity levels, one must be cautious in applying the DCF method.  While typical cycle highs and lows can be dealt with through an analysis of historical industry cycles, periods of extreme highs, or extreme lows, create unusual challenges for OFS forecasting.  No matter the level of industry experience, extreme industry activity (high or low), can easily lead to forecasts that result in unreliable indications of value.  In such instances, while application of an income approach DCF methodology may be warranted and appropriate, it may be the case that reliance on the indication of value derived from this methodology should be afforded less weight relative to the weight afforded indications of value from other valuation methods - likely a market approach guideline company methodology. ConclusionAs indicated, the unpredictable cyclicality of the OFS industry requires careful consideration of many industry-wide and company-specific factors in developing a reasonable forecast of future operating results.  While consideration of such factors should be part of the analysis in the appraisal of businesses in all industries, the impact of these considerations is magnified in highly cyclical industries such as that served by OFS businesses.Mercer Capital has a breadth and depth of experience in the appraisal of businesses in the oil and gas industry that is rare among independent business appraisal firms.  Our Energy Team is led by professionals with 20 to 30+ years of experience involving upstream businesses (E&Ps, oilfield product manufacturers and oilfield service providers), midstream (gathering systems, pipeline MLPs, pipeline processing facilities), and downstream (refining, processing, and distribution).   Feel free to contact us to discuss your valuation needs in confidence. 1 EIA: Trends in U.S. Oil and Natural Gas Upstream Costs – March 2016

Over the last 12 years the oilfield waste water disposal industry has grown exponentially, both on an absolute basis, and by rank of its importance/size among the oilfield services. This growth has been largely driven by the increased volumes of waste water generated in the production of oil from shale plays. This post discusses the basics of salt water disposal which has become so important given the rise of hydraulic fracturing.The Impact of the Shale BoomThe shale revolution, starting in the Bakken formation in 2007 and ramping-up in the Eagle Ford and Permian basins beginning in 2011, was largely propelled by the combination of horizontal drilling and hydraulic fracturing (commonly, “fracking”).Over the last 12 years the oilfield waste water disposal industry has grown exponentiallyBecause shale hydrocarbon deposits are located in tight-rock formations, the naturally occurring produced water (water that is naturally present in oil and gas formations, referred to as “formation water”) to oil ratio is lower than in conventional reservoirs that have increased pore space and connectivity. To economically produce oil/gas from unconventional reservoirs composed of shale or tight (low permeability) rock, the reservoir must be stimulated by a process such as fracking.Fracking increases the hydrocarbon flow capacity by creating cracks (fractures) that are then filled with a permeable media (proppant) that allows oil/gas to move out of the rock formation and into the wellbore. Fracking requires very large volumes of water to be pumped into the reservoir to carry proppant and other fluids into the fractures. That water flows back after the frack is complete. When added to naturally occurring produced water, and produced water resulting from other stimulation operations (water flooding and/or steam flooding), fracking results in water/oil production ratios that can exceed 10:1. This results in enormous volumes of produced water (tens of billions of gallons each year), some of which is utilized in additional stimulation activities, but much of which must be disposed of.The Need for Disposal and MeansProduced water (also referred to as “brine”) contains a number of contaminants, both naturally occurring (salt, oils/grease, and organic/inorganic chemicals) and chemical additives utilized in the drilling and operation of the well. Even after treatment to extract some of the impurities, the resulting water (referred to as “salt water”) contains significant contaminants and must be handled carefully and disposed of properly.The method of salt water disposal depends on a number of factors: geology, technology, area infrastructure, and the prevailing climate in the areaThe method of salt water disposal depends on a number of factors, notably the geology of the formation from which the water is produced, as well as the technology and infrastructure available in the area and the prevailing climate in the area. While some particularly arid regions allow for disposal via evaporation from large holding pits, most salt water is disposed of at specialty disposal sites where the salt water is injected by way of a disposal well (salt water disposal, or SWD wells) into natural underground formations.Geographic DistributionA large portion of the U.S. SWD facilities are located in Texas due to the disproportionate amount of shale acreage in the state and the SWD conducive geology in Texas. Far fewer SWD facilities are located in other shale areas, such as the Marcellus and the Bakken, due to less favorable geological formations in those areas. The Marcellus in particular lacks favorable formations for disposal purposes with the number of recent operating SWD wells in Pennsylvania at less than 100, compared to more than 12,000 SWD wells in Texas.Location SelectionWhen siting a SWD facility, a number of factors come into play, including demand, proximity, and geology.DemandDemand might seem to be an easy consideration – just locate the facility in an area where oil and gas operators are generating large volumes of waste water. However, oil production and, therefore, waste water production, in particular areas can vary widely over both short and long periods of time.When siting a salt water disposal facility, a number of factors come into play, including demand, proximity, and geologyProduction in a particular field naturally declines over time as reserves are depleted, but can increase again with technology advances. Oil prices dictate if it’s economically viable for continued production in a particular field, with oil prices being notoriously unstable compared to many commodities due to supply and demand, country-specific political forces and even geopolitical forces.ProximityProximity to the area of waste water disposal demand is important. Proximity can be viewed both as distance and as the availability of the appropriate infrastructure (roads) to efficiently transport the waste water from the production site to the disposal site. Transporting oilfield waste water is a significant expense and for obvious reasons is tied directly to the transport distance. Many oil and gas wells are located in remote areas where the existence of roads, or lack thereof, plays into the SWD location decision.GeologySurface location isn’t the only consideration when choosing a SWD facility site. The location’s geology is just as important.A porous and permeable, non-hydrocarbon bearing zone that is not considered an aquifer under the UIC program is one possible geological formation appropriate for salt water disposal. A second possibility would be a previously depleted oil and gas zone, that is both porous and permeable.For either option, a clear barrier must exist between the target zone and all underground sources of drinking water ("USDWs"), and the drill area needs to be generally clear of any significant geologic faults.ConstructionSalt water disposal wells have very specific construction requirements in order to ensure that there will be no contamination of the area USDW or the environment in general. For example, in Texas, salt water disposal wells are constructed with three layers of casing to ensure that groundwaters are not impacted. The surface casing (the first layer) is a cement encased steel pipe that extends from ground level to a specific minimum distance below the deepest USDW level. The production casing, a pipe that is permanently cemented in the wellbore, is the second casing layer and runs the length of the well. The third protection layer contains the injection tubing string that guides the injected water to the bottom of the well for discharge into the target formation. This construction provides the most secure means of disposing of salt water developed to date in that all three pipes would have to fail at the same time for surrounding groundwater to be contaminated.RegulationRegulation of SWD facilities is significant and thorough. The 1974 Safe Drinking Water Act required the U.S. Environmental Protection Agency ("EPA") to set minimum requirements for salt water injection wells, along with many other wells utilized in disposing of various hazardous and nonhazardous wastes. These EPA established requirements are generally referred to as the Underground Injection Control ("UIC") program. Since the inception of the UIC program, wells classified for injection of oilfield waste liquids have been used to inject over 30 trillion gallons of oilfield salt water without endangering USDWs.Regulation of salt water disposal facilities is significant and thoroughThe UIC program established the necessary requirements for a state to enforce the program within their jurisdiction. In order to assume primacy, the states must demonstrate that their program for UIC enforcement meets the minimum requirements established by the UIC program. At the current time, 33 states and three U.S. territories have primacy for the UIC wells in their jurisdiction. Seven states share primacy with the EPA with the state typically handling one or more classifications of wells and the EPA overseeing the remaining classifications. The EPA maintains primary enforcement of the UIC programs in the remaining ten states and three U.S. Territories.EconomicsA commercial SWD well operator will typically charge between $0.50 and $2.50 per barrel of salt water. The wide range is a simple result of supply and demand. In areas where disposal demand is low, where SWD wells are abundant and have significant capacity availability, the per barrel rate trends towards the lower end of the range. That contrasted with areas where demand for salt water disposal is strong, but the disposal infrastructure, or capacity, is lacking, or the geology places limits on the injection of oilfield waste water, the commercial SWD operators are able to charge fees in the upper end of the range.A commercial salt water disposal well operator will typically charge between $0.50 and $2.50 per barrel of salt waterAnother consideration associated with disposal of oilfield waste water is the cost of transporting the salt water from the well site to the disposal site. Typically the transportation of waste liquids will cost the operator $1.00 per barrel per hour of transport time. In an area of SWD facility abundance, such as the Barnett shale, transport expense might only add $0.50 per barrel to salt water disposal expenses. However, in areas with few SWD facilities, such as some Pennsylvania locations, oilfield waste fluids have to be trucked to disposal facilities in Ohio or West Virginia, with the cost adding $4.00 to $6.00 per barrel.ConclusionWatch this space for future blog posts addressing the valuation issues faced by companies operating in this space.Mercer Capital has significant experience valuing assets and companies in the oil and gas industry. Because drilling economics vary by region, as touched on above, it is imperative that your valuation specialist understand the local economics impacting your company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 auditors. These oil and gas related valuations have been used to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Sourceshttp://www.oilandgas360.com/water-handling-in-oilfield-operationshttp://www.tech-flo.net/salt-water-disposal.htmlhttp://www.producedwatersociety.com/produced-water-101http://aqwatec.mines.edu/produced_water/intro/pw/http://www.epa.gov/sites/production/files/documents/21_McCurdy_-_UIC_Disposal_508.pdf